&EPA
United States
Environmental Protection
Agency
Office Of Water
(4303)
EPA821-R-95-012
February 1995
Economic Impact Analysis For
Proposed Effluent Limitations
Guidelines And Standards For
The Coastal Subcategory Of The
Oil And Gas Extraction Point
Source Category
QUANTITY
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ECONOMIC IMPACT ANALYSIS FOR PROPOSED EFFLUENT LIMITATIONS
GUIDELINES AND STANDARDS FOR THE COASTAL SUBCATEGORY OF THE
OIL AND GAS EXTRACTION POINT SOURCE CATEGORY
Prepared for:
U.S. Environmental Protection Agency
Office of Water
Office of Science and Technology
Engineering and Analysis Division
Economic and Statistical Analysis Branch
Washington, DC 20460
Prepared by:
Eastern Research Group, Inc.
110 Hartwell Ave
Lexington, MA 02173
January, 1995
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CONTENTS
SECTION ONE EXECUTIVE SUMMARY 1-1
1.1 Overview 1-1
1.2 Data Sources 1-2
1.2.1 The Coastal Mapping Database .. 1-2
1.2.2 The Coastal Oil and Gas Questionnaire 1-3
1.3 Industry Profile 1-3
1.3.1 Drilling and Production Activities That Generate Waste ,. 1-4
1.3.2 General Overview of the Affected Coastal
Subcategory Industry 1-4
1.4 Economic Impact Analysis Methodology Overview 1-9
1.4.1 Aggregate Compliance Costs 1-14
1.5 Economic Methodology 1-16
1.5.1 Economic Models for Cook Inlet, Alaska, and
the Gulf of Mexico 1-16
1.5.2 Production Loss Modeling Results 1-18
1.6 Economic Impacts on Coastal Oil and Gas Firms 1-24
1.6.1 Results of Baseline Analysis/Screening Analysis 1-25
1.6.2 Results of Detailed Analysis of Firms in the
Gulf of Mexico Region 1-26
1.7 Employment and Community-level Impacts 1-27
1.7.1 Primary and Secondary Employment Losses 1-27
1.7.2 Labor Requirements and Potential Employment Benefits 1-30
1.73 Net Effect of Employment Losses and Gains 1-32
1.8 Impacts on the Balance of Trade, Inflation, and Consumers 1-32
1.9 Regulatory Flexibility Analysis 1-33
1.10 Impacts on New Sources 1-34
SECTION TWO DATA SOURCES 2-1
2.1 Introduction 2-1
2.2 The Coastal Mapping Database 2-2
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CONTENTS (continued)
23 The Coastal Oil and Gas Questionnaire 2-4
2.4 References : 2-7
SECTION THREE INDUSTRY PROFILE 3-1
3.1 Introduction 3-1
3.2 The Process of Oil and Gas Extraction and the Wastes Generated 3-6
3.2.1 Drilling Operations 3-6
3.22 Production Activities '...' 3-9
3.23 Miscellaneous Wastes 3-10
3.3 General Overview of the Affected Coastal Subcategory Industry 3-13
3.3.1 The Affected Coastal Subcategory Industry Compared to
the U.S. Oil and Gas Industry 3-13
3.3.2 Trends in the Affected Coastal Subcategory 3-15
333 Detailed Discussion of Wells, Facilities, and Firms 3-17
3.4 References 3~39
SECTION FOUR ECONOMIC IMPACT ANALYSIS METHODOLOGY OVERVIEW
AND AGGREGATE COMPLIANCE COST ANALYSIS 4-1
4.1 Overview of Methodologies 4-1
4.2 Cost Annualization Purpose and Method 4-4
43 The Regulatory Options - 4-6
43.1 Produced Water 4-8
43.2 Drilling Fluids and Cuttings 4-10
433 TWC Wastes 4-11
43.4 Other Miscellaneous Wastes 4-12
4.4 Aggregate Compliance Costs .' 4-12
4.4.1 BAT Options 4-13
4.4.2 NSPS Cost Estimate for Produced Water 4-21
4.43 NSPS Cost Estimate for TWC 4-21
4.4.4 Total Estimated Cost of the Effluent Guidelines 4-23
4.5
References
4-23
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CONTENTS (continued)
SECTION FIVE PRODUCTION LOSS IMPACTS AND OTHER IMPACTS
TO WELLS AND FACILITIES 5-1
5.1 Description of the Economic Model for Cook Inlet, Alaska 5-2
5.1.1 Economic Model Overview 5-2
5.12 Model Parameters 5-3
5.13 Model Calculation Procedures 5-7
5.1.4 Interpretation of Model Results 5-10
5.13 Parameter Values and Data Sources 5-12
5.1.6 Calculation Procedures 5-16
5.2 Description of the Economic Model for the Gulf of Mexico 5-16
5.2.1 Economic Model Overview • .-• 5-16
5.3 Production Loss Modeling Results 5-18
5.3.1 Gulf of Mexico 5-19
5.3.2 Cook Inlet 5-25
5.33 Total Impacts—Gulf of Mexico Wells and Cook Inlet
Platforms, Produced Water Options 5-31
5.3.4 Impacts From the Co-proposed Regulatory Options for TWC ... 5-33
5.3.5 Total Impacts, Selected Options 5-33
5.4 References 5-35
SECTION SIX ECONOMIC IMPACTS ON COASTAL OIL AND GAS FIRMS .. 6-1
6.1 Analytical Methodology 6-2
6.1.1 Baseline Methodology 6-2
6.1.2 Screening Methodology 6-2
6.13 Detailed Analysis 6-4
6.2 Sources of Data 6-5
6.3 Use of Data in the Analysis 6-8
6.4 Results of Firm-Level Analysis 6-9
6.4.1 Baseline Analysis 6-10
6.42 Detailed Analysis 6-22
6.5
References
6-27
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CONTENTS (continued)
SECTION SEVEN EMPLOYMENT AND COMMUNITY-LEVEL IMPACTS 7-1
7.1 Primary and Secondary Employment Losses 7-2
7.1.1 Introduction 7-2
7.12 Methodology 7-2
7.13 Results—Employment Impacts From BAT Options 7-7
7.2 Labor Requirements and Potential Employment Benefits 7-12
7.2.1 Introduction 7-12
7.2.2 Estimating Direct Labor Requirements 7-13
7.23 Estimating the Secondary (Indirect and Induced)
. Labor Requirement Effects 7-23
7.3 Net Effect of Employment Losses and Gains 7-24
7.4 References 7'25
SECTION EIGHT IMPACTS ON THE BALANCE OF TRADE, INFLATION, AND
CONSUMERS 8-1
8.1 Impacts on the Balance of Trade 8-1
8.2 Impacts on Inflation and Consumers 8-2
83 . References • 8-2
SECTION NINE REGULATORY FLEXIBILITY ANALYSIS 9-1
9.1 Introduction • 9-1
9.2 Summary of EPA Guidelines on RFA Requirements 9-1
9.3 IRFA Information Requirements 9-3
9.3.1 Reasons for Taking Action and Objectives of and
Legal Basis for the Proposed Rule 9-3
932 Estimates of the Affected Population of Small Businesses 9-4
9.33 -Projected Recordkeeping and Reporting Requirements 9-4
93.4 Other Federal Requirements .9-6
9.35 Significant Alternatives to the Proposed Rule 9-6
9.4
Profile of Small Coastal Oil and Gas Firms 9-7
IV
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CONTENTS (continued)
9.5 Impacts on Small Coastal Oil and Gas Firms 9-11
9.5.1 Results of Screening and Firm Failure Analysis 9-11
9.6 References 9-13
SECTION TEN IMPACTS ON NEW SOURCES 10-1
10.1 References 10-2
APPENDIX A
APPENDIX B
APPENDIX C
ECONOMIC ASSUMPTIONS USED IN THE
PRODUCTION LOSS MODEL A-l
EPA ECONOMIC MODEL FOR COASTAL PETROLEUM
PRODUCTION IN COOK INLET, ALASKA B-l
GULF OF MEXICO PRODUCTION LOSS MODEL C-l
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LIST OF TABLES
Table 1-1 Industry Profile of the Affected Segment of the Coastal Subcategory:
Gulf Coastal (Louisiana and Texas only) and Cook Inlet vs.
Total U.S. Industry ,• I-5
Table 1-2 BAT Regulatory Options Considered in the Economic Impact
Analysis '1-13
Table 1-3 Total Economic Impacts (Including Production Losses): Gulf of Mexico
and Cook Inlet Regions Combined " 1-19
Table 1-4 Total Economic Impacts to Gulf of Mexico and Cook Inlet Regions
From the Selected Options • • • • • • 1-23
Table 1-5 Baseline and Postcompliance Employment Losses (FTEs) 1-29
Table 1-6 Total Estimated Direct Employment Gains: Gulf of Mexico and
Cook Inlet Regions 1-31
Table 2-1 Presurvey Estimate of Number of Coastal Wells by Location 2-5
Table 2-2 Status of the Questionnaire Response 2-8
Table 3-1 Status of Coastal Regions Outside Texas, Louisiana, and
Cooklnlet 3-2
Table 3-2 Industry Profile of Affected Segment of the Coastal Subcategory:
Gulf Coastal (Louisiana and Texas only) and Cook Inlet
vs. Total U.S. Industry 3-14
Table 3-3 Platforms, Operators, and Wells in Cook Inlet 3-22
Table 3-4 Produced Water Treatment Facilities in Cook Inlet 3-26
Table 3-5 Median Financial Statistics on Assets, Equity, and Working Capital—
All Firms, Gulf • 3-30
Table 3-6 Median Financial Statistics on Assets, Equity, and Working Capital-
Discharging Firms, Gulf 3-32
Table 3-7 Median Financial Statistics on Revenues and Costs—All Firms, Gulf .. 3-33
Table 3-8 Median Financial Statistics on Revenues and Costs—Discharging
Firms, Gulf • 3-34
Table 3-9 Median Financial Statistics on Profitability and Ability to Borrow-
All Firms, Gulf • • • • 3-36
Table 3-10 Median Financial Statistics on Profitability and Ability to Borrow—
Discharging Firms, Gulf '. • 3-37
Table 3-11 Median Financial Statistics—All Firms, Cook Inlet 3-40
Table 4-1 BAT Regulatory Options Considered in the Economic Impact
Analysis 4'9
Table 4-2 Aggregate Annual Costs for BAT Options by Regulatory Options 4-14
Table 4-3 Drilling Schedule • 4-16
Table 4-4 Cost Annualization of Drilling Costs for 1-Million-ppm Toxicify Limit . 4-17
Table 4-5 Cost Annualization of Drilling Costs for Zero-Discharge Option 4-18
Table 4-6 Aggregate Annual Costs for Selected BAT Regulatory Options 4-20
Table 4-7 Total Annual Costs for All Selected Regulatory Options 4-22
Table 5-1 Cook Inlet Production Loss Model: Common Parameter Values 5-5
Table 5-2 Cook Inlet Production Loss Model: Summary of Platform Data
and Inputs 5'6
Table 5-3 Results of the Production Loss Modeling in the Gulf Region 5-21
Table 5-4 Impacts of Produced Water Options on Cook Inlet Platforms 5-27
Table 5-5 Impacts of Drilling Waste Options on Cook Inlet Platforms 5-29
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LIST OF TABLES (continued)
Table 5-6 Total Economic Impacts (Including Production Losses): Gulf of
Mexico and Cook Inlet Regions Combined 5-32
Table 5-7 Total Economic Impacts to Gulf of Mexico and Cook Inlet Regions
From the Selected Options 5-34
Table 5-8 Impacts of Option #4 Produced Water and Option #3 Drilling
Waste on Cooklnlet Platforms 5-35
Table 6-1 Changes in Equity and Working Capital Associated With
the Improved Gas Flotation Option (Gulf of Mexico) 6-11
Table 6-2 Range and Median Change in Equity and Working Capital
Associated With the Improved Gas Rotation Option
(Gulf of Mexico) 6-13
Table 6-3 Changes in Equity and Working Capital Associated With
the Zero-Discharge Option (Gulf of Mexico) 6-14
Table 6-4 Range and Median Change in Equity and Working Capital
Associated With the Zero-Discharge Option (Gulf of Mexico) 6-15
Table 6-5 Improved Gas Flotation Option: Equity and Working Capital Changes
for Large Operators (Gulf of Mexico) 6-16
Table 6-6 Zero Discharge: Equity and Working Capital Changes
for Large Operators (Gulf of Mexico) 6-17
Table 6-7 Improved Gas Flotation: Equity and Working Capital Changes
for Small Operators (Gulf of Mexico) 6-18
Table 6-8 Zero Discharge: Equity and Working Capital Changes
for Small Operators (Gulf of Mexico) 6-20
Table 6-9 Results of Further Financial Analysis of Selected Coastal
Region Oil and Gas. Production Operators (Gulf of Mexico) 6-23
Table 7-1 Baseline and Postcompliance Employment Losses (FTEs) 7-8
Table 7-2 Analysis of Possible Direct Employment Generation Effects of Effluent
Guidelines for the Coastal Oil and Gas Industry—Gulf Region 7-19
Table 7-3 Analysis of Possible Direct Employment Generation Effects of Effluent
Guidelines for the Coastal Oil and Gas Industry—Cook Inlet 7-20
Table 7-4 Total Estimated Direct Employment Gains: Gulf of Mexico and
Cook Inlet Regions 7-22
Table 9-1 Numbers of Coastal Oil and Gas Firms by Size 9-5
Table 9-2 Profile of Coastal Oil and Gas Firms by Size: Financial Indicators 9-8
Table 9-3 Profile of Coastal Oil and Gas Firms by Size: Oil and Gas
Costs and Revenues 9-9
Table 9-4 Baseline Firm Failures by Size of Firm 9-10
Table 9-5 Postcompliance Firm Failures by Size of Firm 9-12
Table B-l Exogenous Variables Used in the Cook Inlet Production Loss Model .. B-9
Table B-2 Cost and Cash Flow Uses in the Cook Inlet Production Loss Model ... B-18
Table C-l Exogenous Variables Used in the Gulf of Mexico Production
Loss Model C-10
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LIST OF FIGURES
Figure 1-1 Overview of methodology for the economic impact analysis 1-11
Figure 1-2 Overview of closure analysis methodology 1-17
Figure 3-1 Location of the Gulf of Mexico coastal region in Texas
and Louisiana 3-4
Figure 3-2 Map of Cook Met region 3-5
Figure 3-3 Overlap of ERG Polygon and the Gulf of Mexico coastal region 3-19
Figure 4-1 Overview of methodology for the economic impact analysis 4-3
Figure 5-1 Overview of closure analysis methodology 5-4
Figure B-l Cook Inlet production loss model B-4
Figure C-l OihWater relationship over time C-4
Figure C-2 Gulf of Mexico production loss model C-5
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SECTION ONE
EXECUTIVE SUMMARY
1.1 OVERVIEW
This economic impact analysis (EIA) examines compliance costs and economic impacts
resulting from the U.S. Environmental Protection Agency's (EPA's) proposed revisions to
effluent limitations guidelines and standards for the Coastal Subcategory of the U.S. oil and gas
industry. The EIA estimates economic impacts in terms of anmialized costs; production losses;
and changes in equity, working capital, and other indicators of financial health at the firm level.
In addition, impacts on employment and affected communities, foreign trade, and new sources
are considered. A Regulatory Flexibility Analysis detailing the impacts on small businesses
within the coastal oil and gas industry also is included in the EIA, The impacts measured in the
EIA do not take into account the requirements of the EPA Region 6 General Permits for the
Coastal Oil and Gas Industry covering disposal of produced water (60 FR 2387, January 9,1995).
This Executive Summary follows the general outline of the EIA. Section 1.2 summarizes
the primary data sources used for the EIA and Section 1.3 profiles the coastal oil and gas
industry. Section 1.4 presents an overview of the methodology used in the EIA, focusing on the
cost annualization model. Section 1.5 presents the specific economic methodology used, which
focuses on production loss modeling, and Section 1.6 investigates firm-level impacts. Sections 1.7
and 1.8 analyze employment and community-level impacts, and impacts on foreign trade,
respectively. Section 1.9 presents the Regulatory Flexibility Analysis and Section 1.10 investigates
impacts on new sources.
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1.2 DATA SOURCES
1.2.1 The Coastal Mapping Database
This EIA relies on a number of sources of information, but primarily it uses the Section
308 Survey of the Coastal Oil and Gas Industry, which was undertaken exclusively to provide
data necessary for this rulemaking. Most of the data used to determine the wells to be surveyed
were developed using several existing computerized well databases covering wells in southern
Louisiana and eastern Texas. Four mapping phases were undertaken using information from
these databases:
• Phase I—Wells in southern Louisiana and eastern Texas were divided into
offshore/federal waters, offshore/state waters, and coastal/onshore categories. A
total of 508 wells were identified as located in federal offshore waters, 1,296 were
identified as located in state offshore waters, and 8,778 were identified as
potential coastal wells (i.e., they were not in offshore waters).
• Phase n—To simplify the task of more precisely determining whether these 8,778
wells were located in coastal areas, nonproductive wells needed to be eliminated
from the analysis. Wells that were never produced—4,645 wells—were
eliminated, leaving 4,133 that had produced at some time.
• Phase m—Currently nonactive wells were eliminated from consideration. Wells
that were currently productive as of September 1991 were identified as active
wells in the coastal database. A total of 2,710 wells were determined to be active.
• Phase IV—A number of the wells in Phase in could be clearly identified as
coastal by their location in a body of water; however, hundreds of wells were
further analyzed during this phase to determine their status using U.S. Fish and
Wildlife Service wetlands maps and geographic information system (GIS) data.
Following the phased mapping effort, data on current ownership was purchased from the
Louisiana Department of Natural Resources (DNR) and Texas Railroad Commission (RRC) and
analyzed. Seventy wells were identified at this time as onshore and were dropped from the data
set The final result was a list of 354 operators and 2,640 wells in the Gulf of Mexico coastal
region.
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1.22 The Coastal Oil and Gas Questionnaire
Once the Section 308 survey universe was defined, the survey was conducted using the
1993 Coastal Oil and Gas Questionnaire. The questionnaire collected information regarding
waste stream generation, treatment, and disposal; the costs of treatment and disposal; and the
financial status of the firms in the coastal oil and gas industry.
EPA identified 361 operators of oil and gas wells in the coastal subcategory—354
operators in southern Louisiana and eastern Texas, and 7 operators in Cook Inlet and the North
Slope of Alaska. EPA identified a population of 3,623 coastal subcategory oil and gas wells
(2,640 Louisiana and Texas wells and 983 Cook Inlet and North Slope wells). The 2,640
Louisiana and Texas wells were those completed since 1980. Information on wells completed
prior to 1980 was unfortunately prohibitively expensive because of the proportionately greater
number of pre-1980 wells in proprietary databases. The post-1980 population of weDs was
divided into three subpopulations, enabling EPA to conduct a census of wells within some
categories and sample wells in others. EPA conducted a census of all wells that were controlled
by small operators (i.e., operators with only one well in the coastal subcategory) and all wells on
multiwell structures, then sampled other wells in the population. Survey results throughout this
EIA are weighted according to EPA's sampling plan. Survey results are also extrapolated in
subsequent analyses to the estimated number of pre-1980 wells for which survey data are
unavailable.
INDUSTRY PROFILE
The proposed effluent limitations guidelines and standards for the coastal oil and gas
industry will affect a very small portion of the overall U.S.'oil and. gas industry. Following
investigation of the current and projected oil and gas activities in the coastal region, the types of
state regulations already in place, and current practices, the areas of most concern in this EIA
were identified as the Gulf of Mexico coastal region of Louisiana and Texas and the coastal
region of Cook Inlet, Alaska. The coastal region of Louisiana and Texas will be known as the
Gulf region throughout the remainder of this EIA, since only these two states have Gulf coastal
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operations known to discharge wastes. Outside of Texas and Louisiana, costs and impacts of the
regulation are estimated to be zero. Due to a number of regulatory requirements already in
place, wells in Alabama, Florida, California, and North Slope in Alaska are already achieving
zero discharge, and no production activity is occurring or projected in Mississippi or the mid-
Atlantic region of Virginia and Maryland. Table 1-1 presents information on production,
number of establishments, and number of wells in Texas, Louisiana, and Cook Inlet as a portion
of the U.S. oil and gas industry. Note that the estimates in this table incorporate extrapolations
to pre-1980 wells, which were not surveyed.
1.3.1 Drilling and Production Activities That Generate Wastes
Two activities in the oil and gas extraction process generate the major portion of wastes
in this industry: drilling activities and production activities. Because the entire subcategory
except for Cook Inlet is subject to zero discharge requirements, the drilling operations of concern
in this analysis are the drilling operations in Cook Inlet. The most significant waste streams, in
terms of volume and constituents associated with drilling activities, are drilling fluids and drill
cuttings. The major waste streams associated with production activities are produced water, and
to a much lesser extent, produced sand. Miscellaneous wastes also can be generated during the
productive life of a well. The three most common miscellaneous wastes are known as treatment,
workover, and completion (TWC) wastes. An economic impact analysis is not being conducted
on other effluent wastes generated by this industry because EPA's preferred options for these
wastes are equivalent to current requirements or practices.
1.3.2 General Overview of the Affected Coastal Subcategory Industry
.1 Trends in the Affected Coastal Subcategory
The trends of concern evaluated in this EIA are the rate at which production is expected
to decline with time and the expected trend for the wellhead price of oil.
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An analysis of data used to determine the location of wells in the Gulf of Mexico coastal
region reveals that well production tends to decline at a rate of 12 to 15 percent per year.
The U.S. Department of Energy (DOE) estimates that overall production is declining in the
United States at a rate of about 3 percent per year. The choice of decline rate affects the
calculation of total lifetime production. The 3 percent national estimate and the 15 percent
high-end well-specific estimate can be used to bound the decline rate for the Gulf of Mexico.
Lifetime production in terms of barrels of oil equivalent (BOE) (a measure that combines units
of oil and gas on the basis of Btu content) was calculated for the Gulf of Mexico region using
the present (1992) estimated production of 159.2 million BOE and both the high and low
estimate of potential decline over the 30-year horizon. This calculation results in a total lifetime
production estimate (i.e., total production over a 30-year time frame) for the Gulf of Mexico
ranging from 692.5 million to 1,391.2 million BOE.
Information provided by Cook Inlet operators indicates that the typical decline rate for
Cook Inlet wells is about 8 percent per year. Expected lifetime production, based on this decline
rate and the number of wells and recompletions expected to be undertaken in the Inlet, is
estimated to be 198.1 million BOE with a net present value1 of $417.2 million.
Along with production declines, revenues, employment, and other indicators of industry
vitality also will tend to decline. As larger firms leave the area in search of more profitable
ventures, small firms take over. Thus, the trend over time in the Gulf coastal region is toward a
less highly concentrated industry (i.e., many firms, each with a very small share of the market)
with many very small firms.
For the purposes of this analysis the price of oil is assumed to be constant. This
assumption is consistent with current forecasts of oil prices, which indicate oil prices rising at
about the same rate as inflation (i.e., the real price of oil is not expected to increase through the
rest of this decade).
^Total production revenues minus production costs over the lifetime of platforms in the Inlet
discounted to the present.
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1.3.2.2 Detailed Discussion of Wells, Facilities, and Firms
Wells or Platforms in the Coastal Region
According to estimates from the Section 308 survey, there are currently 2,548 producing
wells (out of 2,640 wells in the survey universe, some of which were found to be nonproductive in
1992) in the affected coastal subcategory. The total number of pre-1980 wells is estimated to be
2,127. Therefore, the total number of Gulf of Mexico coastal wells is estimated to be 4,675. The
typical Gulf coastal well produces both oil and gas. A total of 7 percent of Gulf coastal wells are
gas only, 9 percent are oil only, and 84 percent produce both oil and gas. Total production in
the Gulf of Mexico is estimated at 42.8 million bbls of oil and 653.7 Mcf of gas, or 159.2 million
barrels of oil equivalent (BOE) annually.
There are 15 platforms located in Cook Inlet, of which 14 are considered operational or
potentially operational. A total of 237 wells are currently producing on these platforms. There
are also 208 oil or service wells and 29 gas wells in Cook Inlet. Total annual production in 1993
was 12.9 million bbls of oil and 120.5 Mcf of marketable gas. Total production over the
remaining productive lifetime of the Cook Inlet platforms is estimated at 198 million BOE.
Produced Water Treatment Facilities in the Coastal Region
In 1992, according to permit databases provided by the Louisiana and Texas, there were
325 produced water treatment/separation facilities discharging in the Gulf coastal region. Based
on compliance schedules set up by Louisiana Department of Environmental Quality (DEQ),
court-ordered requirements, and results of the Section 308 survey, facilities that are required to
(or that will) achieve zero discharge by the time the rule is scheduled to be promulgated (July
1996) were removed from the list of dischargers to create a list of facilities expected to be
discharging in 1996, which includes 216 facilities.
The average produced water discharge rate from Gulf coastal facilities is 1,923 barrels per
day (bpd) for facilities that inject produced water and 2,069 bpd for facilities that discharge
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produced water. Currently, produced water treatment facilities in the Gulf of Mexico are
designed to meet best practicable technology (BPT) requirements, which restrict the oil and
grease concentrations of produced water to a maximum of 72 mg/L for any one day and to a 30-
day average of 48 mg/L. Several technologies are used to achieve this level of control. The
typical Gulf coast discharging facility uses gravity separators, which are tanks large enough to
store oil and water mixtures for a sufficient length of time to allow the mixture to separate.
Because Cook Inlet is typified by multiwell platforms, the platform is considered the unit
of production in the Cook Inlet analysis, and the parameters used to model production are
defined by platform. There are three land-based and five platform-based separation/treatment
facilities in Cook Inlet. About 98 percent of all produced water is treated and discharged from
the three land-based facilities. Produced water is generated at a rate of about 127 thousand bpd
in Cook Inlet. Six facilities use skim tanks only, or a combination of skim tanks and corrugated
separators for treatment (four platform-based and two land-based facilities), with two facilities
employing gas flotation (one land-based and one platform-based).
Oil and Gas Firms Operating in the Coastal Region
The expenditures required to comply with the effluent limitations guidelines for the
coastal oil and gas industry will be financed by coastal firms and their investors. Before the
impact of the effluent guidelines were assessed, the EIA evaluated the current financial condition
of these firms, both generally and in comparison with the overall domestic oil and gas industry.
Firms Operating in the Gulf of Mexico
Coastal petroleum producers can be divided into two basic categories: major integrated
oil companies and independents. The major integrated oil companies are generally larger than
the independents. As a group, the majors generally produce more oil and gas, earn significantly
more revenue and income, have considerably larger assets, and have greater financial resources
than the independents, and according to the Section 308 Survey, probably are somewhat more
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financially healthy than the independents as a group. Independents can be broken down by both
size and by corporate structure. Larger firms tend to be corporations; smaller firms tend to be S
corporations, limited partnerships, sole proprietorships, and other types of structures.
Several analyses were performed to determine the financial status of the Gulf firms.
Based on the results of these analyses, several overall conclusions about the Gulf coastal
operators can be made. Differences between known dischargers and all operators are probably
not great and are likely to follow no particular pattern. Based on the arbitrary divisions made
between groups in terms of size and corporate structure, in some cases known dischargers appear
possibly a little healthier than nondischargers and in other cases the opposite appears true.
Neither group is particularly financially healthy when compared to the industry as a whole. In
most cases, however, on average, both known dischargers and the group of all Gulf coastal
operators fall within the range between median and lowest quartile, which can be characterized
as weak but not poor financial performance.
Firms Operating in Cook Inlet
The Cook Inlet operators, all majors, generally appear as healthy financially as the Gulf
coast major operators as a group. Thus, they appear to have adequate to good financial health.
1.4 ECONOMIC IMPACT ANALYSIS METHODOLOGY OVERVIEW
This analysis discusses the impacts of the proposed and selected regulatory options for
effluent limitations guidelines and standards for the coastal subcategory of the oil and gas
production industry. The overall analysis covers:
• Compliance costs to industry.
•<. Production losses (in terms of quantities of hydrocarbons not produced compared
to a no-regulation [baseline] scenario).
1-9
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• Lost economic lifetime (i.e., the loss of productive years associated with wells
shutting in earlier under the regulation than under a baseline scenario).
• Numbers of wells immediately ceasing production as a result of the regulation
(first-year shut in).
• Losses of revenues to operators, in terms of annualized losses and net present
value (NPV) of production,2 state governments, and the federal government.
• Firm-level impacts (firm failure analysis).
• Employment impacts (losses and gains in employment).
• Balance of trade and inflation impacts.
• Regulatory flexibility (an analysis of whether impacts are disproportionate on
small businesses).
• Impacts on new sources (which looks at impacts on NPV and the internal rate of
return [another measure of profitability]).
These individual analyses are interrelated, with the output of one analysis often used as
input for another analysis. The general flow of the analyses and their relationship to one another
are shown in Figure 1-1. Because compliance costs (capital as well as operating and maintenance
[O&MJ costs) are major inputs to all of these analyses, how these costs are annualized is a key
methodological decision. This EIA uses two approaches. To determine annual compliance costs,
a simple annualization method that computes pretax annual costs is used. This cost is applied to
wells in the Gulf of Mexico region in the production loss analysis in Section Five, and to firms in
the firm-level analysis in Section Six. Platforms in Cook Inlet are modeled using a more
sophisticated cost annualization method that takes into account accelerated depreciation and tax
shields to compute a posttax cost faced by producers.
In the simple approach, cost annualization is used to estimate the annual compliance cost
to the operators of new pollution control equipment. Aromatizing costs is a technique that
allocates the capital investment over the lifetime of the equipment, incorporates a cost-of-capital
factor to address the costs associated with raising or borrowing money for the investment, and
2NPV is the total stream of production revenues minus costs over a period of years (the
well's or platform's lifetime) discounted back to present value.
1-10
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Input
Facility-Specific
Volume
Facility-Specific
Capital Costs
Facility-Specific
Operating &
Maintenance Costs
Input
Per-Barrel
Compliance Cost
Production Loss
Model
Baseline versus
Postcompliance
Comparison
Outputs
I
Baseline Firm
Failures
Postcompliance
Firm Failures
Outputs
Loss of Net Present Value
of Production
Federal Tax Revenue Loss
Severance Tax Loss
Loss of Economic Life
First Year Shut-in
Baseline Shut-in
Output
Discount Rate
^l£2£K)3&&K
Lifetime
. input
&f
Input
>7S ^^
1
Annual Cost
I
I
Annual
Compliance
Cost
Firm-Level
Analysis
1 *J
Output
i
Other, Lesser
Impacts
Figure 1-1. Overview cf methodology for the economic impact analysis.
1-11
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includes annual O&M costs. The resulting annualized cost represents the average annual
payment that a given company will need to make to upgrade its facility.
The engineering cost estimates that feed into the cost annualization are based on a set of
regulatory options developed by EPA. The Agency is required under the Clean Water Act to
establish effluent limitations guidelines and standards of performance for industrial dischargers.
To further these requirements, EPA has proposed the following effluent guidelines and
standards:
• BPT—for produced sand only.
» BCT—Effluent reductions employing the best conventional pollutant control
technology.
• BAT—Effluent reductions employing the best available control technology
economically achievable.
• NSPS—New source performance standards covering direct discharging new
sources.
• PSES—Pretreatment standards for existing sources.
• PSNS—Pretreatment standards for new sources.
For the purposes of evaluation, BCT, PSES, NSPS, and PSNS options are identical to
BAT options (although preferred options differ in some cases). No existing indirect dischargers
are known and no new indirect dischargers are anticipated; thus, PSES and PSNS options for
indirect dischargers are not associated with any costs or impacts.
This analysis considers the BAT, NSPS, and BCT options for produced water, drilling
waste, and TWC wastes. Other wastes are covered but these wastes are associated with no costs
or impacts because the preferred options are equivalent to current requirements or practices.
BAT options considered for each of these types of waste are summarized in Table 1-2. Five
BAT options are considered for produced water, three BAT options are considered for drilling
wastes, and two BAT options are considered for TWC wastes. The preferred BAT regulatory
option for produced water is Option #4 (zero discharge except offshore limitations for Cook
1-12
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TABLE 1-2
BAT REGULATORY OPTIONS CONSIDERED IN THE ECONOMIC IMPACT ANALYSIS
Type of
Waste Stream
Produced
water
Drilling
wastes
TWC wastes
Name
Option #1
Option #2
Option #3
Option #4
Option #5
Option #1
Option #2
Option #3
Option #1
Option #2
Description
BPT — current regulatory requirement
Offshore limitations
Zero discharge/BPT Cook Inlet
Zero discharge/offshore limitations
Cook Inlet
Zero discharge
Zero discharge/offshore limitations
Zero discharge/offshore limitations
toxicity limit Cook Inlet
Cook Inlet
plus 1-million-ppm
Zero discharge
BPT
Zero discharge/offshore limitations
Cook Inlet
1-13
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Inlet) and the preferred NSPS option is Option #5 (zero discharge, all). All three drilling waste
options are co-proposed and the preferred NSPS option for drilling waste is NSPS=BAT (i.e.,
whichever BAT option for drilling waste is selected for final promulgation, NSPS will be set
equal to that option). For TWC wastes, both BAT options are co-proposed, and the preferred
NSPS option is NSPS=BAT. The BCT options investigated are the same as the BAT options;
their selection depends on the highest option that meets the BCT cost test.
1.4.1 Aggregate Compliance Costs
1.4J..1 BAT Options
The aggregate annual pretax compliance costs for produced water are derived from
estimates of capital and operating costs for improved gas flotation and zero discharge pollution
control approaches, for both the Gulf of Mexico and Cook Inlet. The aggregate annual pretax
compliance costs for produced water (other than for Option #1) range from $12.4 million to
$50.7 million. The selected option, Option #4, is associated with annual costs totaling $30.9
million.
Aggregate annual pretax compliance costs for drilling wastes are derived from estimates
of capital and operating costs for 100,000- to 1-million-ppm toxicity limit (Option #2) and zero-
discharge pollution control options (Option #3), for Cook Inlet only (operations in all other
areas already practice zero-discharge). Option #1 equals BPT so there are no costs or impacts
associated with Option #1. The aggregate compliance costs for drilling wastes for Option #2 are
$1.4 million per year. Option #3's annual compliance costs are $3.9 million.
Annual pretax costs for disposing of TWC wastes were generated using assumptions
based on Section 308 survey results about volumes discharged, numbers of wells discharging, and
frequency of discharge. Because Cook Inlet platforms discharge TWC with produced wastes, all
costs for TWC disposal in Cook Inlet are accounted for under produced water options. The
compliance costs for disposing of TWC wastes are approximately $0 to $0.6 million annually,
depending on which co-proposed option becomes final.
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1.4.1.2 NSPS Cost Estimate for Produced Water
EPA estimates that six new projects will be constructed in the Gulf of Mexico each year
over the next 15 years (U.S. EPA, 1995). Total capital costs for a zero-discharge option are
estimated to be $2,038,738 and O&M costs are estimated to be $370,549 per year per project.
The total present value of the zero-discharge option is $34.8 million with an annual cost of $4.5
million. Based on industry contacts, EPA estimates no new projects will be constructed in Cook
Inlet.
1.4.1.3 NSPS Cost Estimate for TWC
EPA estimates that 45 new wells wiE be drilled each year and will require annual disposal
of TWC fluids. Costs per year will total $78,831 for each new group of 45 wells drilled. The
total present value of this outlay is $4.4 million, or $0.5 million annually. Depending on which
BAT option is selected for final promulgation, NSPS costs for TWC could, thus, range from $0
to $0.5 million.
1.4.1.4 Total Estimated Cost of the Effluent Guidelines
The total estimated cost of the effluent guidelines is $30.9 to $35.4 million per year for
BAT requirements and $4.5 to $5.0 million per year for NSPS requirements, for a total of $35.3
to $40.4 million per year. Thus, this mlemaking does not qualify as a major rule under Office of
Management and Budget (OMB) guidelines (Executive Order 12866) and a regulatory impact
analysis (RIA) is not required. Furthermore, the total annual compliance costs associated with
the rulemaking are at most only 0.7 percent of annual coastal revenues (Louisiana, Texas, and
Cook Inlet) and 3.3 percent of annual coastal operating costs.
1-15
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US ECONOMIC METHODOLOGY
A production loss model has been developed in this EIA to simulate the economic
performance of coastal production and drilling projects. Analysis of Cook Inlet, Alaska, projects
incorporates current and future production and future drilling in this model, while Gulf of
Mexico projects are analyzed in current production scenarios only because of lack of site-specific
drilling plans such as those available in the Gulf.3 To estimate the effects of the regulatory
approaches being considered, the economic performance of projects is simulated in this analysis
before and after complying with new pollution control requirements (i.e., "baseline" and
"postcompliance" scenarios).
1.5.1 Economic Models for Cook Inlet, Alaska, and the Gulf of Mexico
The production loss model simulates the performance and measures the profitability of a
petroleum production project. For the Cook Inlet region of the coastal subcategdry, a project is
defined as a single platform. For each project, the model calculates the annual posttax cash flow
for each year of operation as well as cumulative performance measures, such as net present value
arid total lifetime petroleum production. The schematic design of the model is summarized in
Figure 1-2. Regulatory approaches are incorporated into the economic model by adding relevant
capital costs and operating expenses to the set of cost data. The model calculates all yearly and
cumulative outputs for both the baseline case and regulated cases for each project. When the
results of these two scenarios are compared (external to the model itself), the incremental effects
of regulation can be discerned.
3The impact to new BAT wells (i.e., development wells added to existing treatment facilities
without extensive site preparation work) in the Gulf coastal region should be minimal since these
wells will typically face the marginal cost rather than the average cost of disposal (the cost to add
an additional volume of produced water to a treatment facility, given sufficient capacity, is much
less than the average cost per existing well to convert to zero discharge. Furthermore, these
costs should be substantially offset by a new development well's rate of hydrocarbon production,
which tends to be much greater per volume of produced water than older wells. It is unlikely
that plans to drill BAT wells will be curtailed because of effluent guidelines requirements, given
the large number of coastal wells currently injecting produced water. Barriers to entry for NSPS
wells are addressed separately in Section Ten.
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Real Discount Rate
Royalties
Severance Taxes
Corporate Taxes
O&M Costs
Depreciation Schedule
Depletion Allowance
Pollution Control Costs
Capital Costs
O&M Costs
Oil & Gas Prices
Production Levels
Decline Rates
Incremental Annual
Costs
Annual Costs
Annual Revenues
Annual Decision
Is Cash Flow Positive?
Operate for
Another Year
Calculate:
Net Present Value
Annualized Costs
Summary Statistics
(includes well/platform lifetime and lifetime production)
Closure Analysis
Comparison of Pre- and Postregulatory Model Results
(external to model):
• Well/platform has shortened economic lifetime
or
• Well/platform closes in first year due to annual costs
exceeding revenues in first year
or
• Well/platform determined to close in first year because
investment in pollution control is not economic:
• Unregulated NPV>0
- Regulated NPV<0
f
Count as Closure:
• Closes in first year
or
• NPV changes from
positive to negative
Compute
Loss of
Revenues
(lifetime)
Figure 1-2. Overview of closure analysis methodology.
1-17
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The methodology used in the economic model for the Gulf of Mexico is similar to the
model used for Cook Inlet with some basic differences, which are discussed in Section Five. The
primary difference is that the well rather than the platform is the basic unit of production
modeled.
Production Loss Modeling Results
Production loss results are organized into baseline modeling results and postcompliance
modeling results and are broken down by region within Section Five of this report.
Postcompliance results include numbers of first-year shut-ins of wells or platforms by option,
production losses, years of production lost, producers' losses in the present value of net income
(i.e., the present value of the future stream of their net income, or net present value), and state
and federal revenues lost.
Toted Impacts — Gulf of Mexico Wells and Cook Inlet Platforms, Produced Water
Options
As Table 1-3 shows, total produced water impacts across both regions tend to increase
with option number. The selected option, Option #4, is associated with 111 wells and no
platforms shutting in and losses in production totaling 15.2 million discounted BOE (which is at
most 1.7 percent of total projected discounted production in the Gulf of Mexico and Cook Inlet
combined) or 32.4 million total BOE. Producer's net present value (over the lifetime of the
discharging wells and platforms) lost totals $153.2 million ($22.8 million annually) or at most 1.4
percent of the projected net present value of production in the Gulf of Mexico and Cook Inlet
combined. Note that these losses include the producer's share of compliance costs. The present
value of taxes lost are estimated at $84.9 million ($12.6 million annually), or 10.1 percent of taxes
collected from discharging coastal wells and platforms in the Gulf of Mexico and Cook Inlet.
The present value of severance tax losses under Option #4 totals $10.7 million ($1.6 million
annually), or 3.8 percent of projected baseline collections in the Gulf of Mexico and Cook Inlet
among discharging coastal wells and platforms. Finally, royalties lost to the states total
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$34.3 million ($5.1 million annually), or 5.1 percent of projected baseline royalties paid to the
states in the Gulf of Mexico and Cook Inlet from discharging coastal wells and platforms^ Note
that if taxes and royalties from nondischargers are considered, these percentages of income lost
would be much lower, given that in 1996 discharging wells will make up only about a third of all
Gulf coastal wells.
Total Impacts—Drilling Options
Option
Option #1 results in no costs or impacts.
Option #2
Option #2 requires drilling wastes to meet a 100,000- to 1-million-ppm toxicity limit, in
addition to offshore requirements. Under this option, there is a loss of lifetime production in
Cook Inlet of 2.7 million discounted BOE (3.6 million total BOB), or 1.4 percent of total
lifetime Cook Inlet production (stemming from three wells that will not be drilled under this
scenario); no platforms shut in during the first year; and the present value of net producer
income' falls by $0.3 million ($0.04 million annually),4 or less than 0.1 percent of baseline net
present value. Average platform lifetime decreases by only 0.2 years (2 months). The present
value of state severance tax collections falls by $133,000 ($19,000 annually, on average over the
11-year life of platforms under this option, or 0.2 percent of baseline) and the present value of
royalties decreases by $4.3 million ($0.6 million, on average, annually, or 1.6 percent of baseline).
The-present value federal tax collections falls by $2.6 million over the life of the platforms ($0.4
million, on average, annually), or 1.1 percent of projected baseline collections.
This small loss results from baseline assumptions. See Section Five for more details.
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Option #3
Option #3 requires zero discharge of all drilling waste. Under this option, no platforms
shut in during the first year, but six wells that are planned to be drilled will not be drilled. The
total lifetime production lost is estimated to be 5.4 million discounted BOE (7.8 million total
BOE), or 2.8 percent of lifetime baseline production. Producers' net present value lost totals
$6.1 million ($0.9 million annually), which is 1.5 percent of total baseline net present value. The
average number of production years per platform under this option is 10.2 years, vs. 11.1 years in
the baseline scenario, a loss of about 1 year.
The present value loss of federal income tax over the lifetime of the platforms is
projected to be $7.9 million ($1.2 million, on average, annually over the 10-year life of platforms
under this option, or 3.4 percent of baseline federal income taxes), with the present value of
severance tax losses totaling $0.3 million ($0.04 million, on average, annually, or 0.5 percent of
baseline severance taxes). The present value of royalty losses to the state totals $9.4 million
($1.4 million, on average, annually), or 3.7 percent of the baseline royalties collected. Total
present value losses to the state from royalties and severance taxes lost are, thus, $9.7 million
($1.44 million, on average, annually).
Impacts from the Regulatory Options for TWC Wastes
Costs of disposing of TWC wastes range from $0 to $605,645 annually for all Gulf of
Mexico wells estimated to currently discharge TWC wastes (a minimum of 334 wells in 1992), or
at most an average of $1,813 per well under Option #2. A typical Gulf of Mexico well produces
an average of 36 barrels of oil per day according to the 1992 Coastal Oil and Gas Questionnaire.
At $18 per barrel, total production revenue at a typical well is estimated to be $237,000 per year.
Thus, TWC waste disposal costs are estimated to be at most 0.8 percent of average annual
production revenues at a typical Gulf of Mexico well, and no major impacts are expected as a
result of either co-proposed option.
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TABLE 1-4
TOTAL ECONOMIC IMPACTS TO GULF OF MEXICO AND COOK INLET REGIONS
FROM THE SELECTED OPTIONS51
Number of wells and
platforms shut in
Discounted production lost
(million BOB)
Total production lost
(million BOB)
Net present value (NPV)
of production lost ($000)
Present value of federal
taxes lost ($000)
Present value of lost
severance taxes ($000)
Present value of lost
royalties ($000)
Total present value of
losses ($000)
Option #4
Produced
Water
111 wells
0 platforms
152
32.4
$153,209
$84,903
$10,676
$34,255
$283,043
Option #2
Drilling
Waste
Dwells
0 platforms
2.7
3.6
$263
$2,586
$133
$4,274
$7,256
Option #3
Drilling
Waste
0 wells
0 platforms
5.4
7.8
$6,089
$7,925
$272
$9^94
$23,680
Total
Impacts
With Option
#2 Drilling
Waste
111 wells
0 platforms
15.2
32.4
$154,584
$85,611
$10,676
$34,255
$285,126
Total
Impacts
With
Option #3
Drilling
Waste"
111 wells
0 platforms
17.9
402
$160,409
$90,950
$10,815
$39,375
$301,549
"Economic impacts from selected options for other regulated waste streams are expected to be
negligible on these results.
""Economic impacts are not additive. Some double counting or undercounting of impacts occurs
in the Cook Inlet analysis if produced water impacts are directly added to drilling waste impacts.
The total reflects the removal of double counting and inclusion of synergistic impacts (see Table
5-8).
Source: ERG estimates.
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152.4 Toted Impacts for att Selected Options
Total maximum impacts for all selected BAT regulatory options (i.«., Option #4,
produced water, and Option #3, drilling waste)5 are estimated to be as follows (see Table 1-4):
111 wells are expected to shut in; up to 17.9 million discounted BOE (40.2 million total BOB)
are estimated to be lost (1.1 to 2.0 percent of projected baseline production in the Gulf of
Mexico and Cook Inlet coastal regions); and up to $160.4 million in net present value of income
($23.9 million annually) is expected to be lost (0.7 to 1.5 percent of the NPV of production in
the Gulf of Mexico and Cook Inlet coastal regions).
The maximum present value of federal and state income taxes lost totals $91.0 million
($13.6 million on average annually—primarily federal), which is 10.8 percent of projected lifetime
income taxes in the baseline collected among discharging wells and platforms. The maximum
present value of state severance taxes lost totals $10.8 million ($1.6 million on average annually),
or 3.8 percent of projected lifetime severance taxes in the baseline collected among discharging
wells and platforms. Finally, the maximum present value of royalties lost totals $39.4 million
($5.9 million on average annually), or 5.8 percent of projected lifetime royalties in the baseline
collected among discharging wells and platforms. Note that impacts on taxes and royalties are
substantially less if taxes and royalties collected from nondischarging wells also are considered.
Total economic impacts (including compliance costs) are as much as $301.5 million present value
($44.9 million annually).
Impacts from Options #4, produced water, and drilling waste Options #2 and #3 are not
additive for Cook Inlet platforms (note that impacts for Option #4, produced water, and Option
#1, drilling waste, are the same as Option #4, produced water, impacts alone). A small double
counting and under counting of impacts occurs.
5The actual total will depend on drilling waste option and will range as low as the impacts
estimated for Option #4, produced water, alone, discussed in Section 1.5.1.2)
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1.6 ECONOMIC IMPACTS ON COASTAL OIL AND GAS FIRMS
The firm-level analysis conducted in the EIA evaluates the effects of regulatory
compliance on firms owning one or more affected coastal oil and gas operators. It also serves to
identity impacts not captured in the production loss analysis.
This analysis was conducted in three stages: a baseline analysis; a screening analysis; and
finally, a detailed analysis. In the baseline analysis, firms with negative equity and working
capital are considered baseline failures and removed from further postcompliance analysis. In
the screening analysis, the annual costs of meeting either an oil and grease limit based on
improved gas flotation or zero-discharge requirement are subtracted from .each firm's equity and
working capital and the percentage decrease in equity and working capital is then calculated.
These declines are compared to a benchmark of 5 percent (i.e., a count is presented of the
number of firms having their equity or working capital reduced by more than 5 percent as a
result of a regulatory option). In the detailed analysis, all firms with a 5 percent or greater
change in either equity or working capital are investigated using all available survey information
and additional financial indicators to refine the initial estimates of potentially substantial impacts
on coastal oil and gas firms.
Sources of data used in these analyses include two databases that provide information on
permit numbers, permit holders, discharge volumes, field names, and other data that EPA
received from the states of Louisiana and Texas. Also used with the permit data are data from
the Section 308 survey. Surveyed Gulf of Mexico firms were linked with known permit holders in
the databases. For several reasons, not all permit holders are included in the Section 308 survey.
Because only 58 surveyed operators with sufficient financial data could be linked to the 122
operators identified in the permit databases as discharging in 1996, estimates of impacts assume
that only half of the relevant operators were captured in this analysis. It is further assumed that
this sample of operators is unbiased, and, thus, estimates of impact are extrapolated to the entire
coastal universe of operators by multiplying results by two.
1-24
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These data are used to identify impacts on firms. For the purpose of this analysis, costs
for meeting no-discharge requirements for the permitted facility are assumed to fall solely on the
operator who holds that facility's permit.
1.6.1 Results of Baseline Analysis/Screening Analysis
1.6J.1 Gutfof Mexico
Five of the 58 matched firms (9 percent) in the Gulf of Mexico region currently have
both negative equity and negative working capital. These firms are considered very likely to fail
the baseline analysis regardless of whether any regulatory actions are taken. Thus, 53 firms were
analyzed in the screening analysis.
All Gulf of Mexico coastal oil and gas firms matched in the analysis database were
investigated to determine changes in equity and working capital resulting from outlays for
incremental disposal costs (produced water costs) by size of firm. Of the firms with positive
equity, 23 small firms and all large firms are expected to experience a change in equity of less
than 5 percent if improved gas flotation is used. If zero discharge were required, no additional
small firms would be expected to experience a change in equity of greater than 5 percent.
Sixteen small firms (40 percent of small firms with positive working capital) and all large
firms would be expected to experience changes in working capital of less than 5 percent if
improved gas flotation were used to meet limits. If zero discharge is required, no additional
firms would be expected to experience a change in working capital of greater than 5 percent.
1.6.1.2 Cook Inlet
None of the five operators in Cook Inlet are expected to experience a change in equity or
working capital of greater than 5 percent under either the option for limits based on improved
1-25
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gas flotation or the zero discharge option for produced water or under the 1-million-ppm toxicity
limit or zero-discharge limit for drilling waste. No further analysis of these firms is undertaken.
1.6.2 Results of Detailed Analysis of Firms in the Gulf of Mexico Region
A number of firms were selected for more in-depth analysis of survey responses in an
attempt to identify conditions that would indicate substantially less impact than that suggested by
the use of a 5 percent change in equity and working capital. Of the small firms not identified as.
baseline failures, 18 small firms were identified for further analysis.
Of these 18 firms, 4 are considered additional baseline failures and 1 is expected to have
already plugged and abandoned the wells that are served by its discharging facility before the
time that the effluent guidelines take effect. Of the remaining 12 firms, 3 firms are not expected
to fail but are expected to plug and abandon wells or sell their wells in response to the regulation
(considered a nonmajor impact). Another 3 firms are expected to experience some impacts, but
not to the extent that firm failure is likely. The remaining six firms lack the information needed
to rule out the possibility of firm failure, although it is very possible that no substantial impact
will actually occur at these firms.
Thus, under either the improved gas flotation or zero-discharge options, a range of 0 to 6
firms might experience firm failure out of a total of 58 operators examined in this analysis (since
as few as none might actually fail). Because there are a total of 122 operators discharging, or
roughly twice the number of operators examined (58 operators screened), the number of firms
experiencing firm failure for all discharges is extrapolated to be a range of 0 to 12 firms. The
upper estimate assumes that firms for which information is lacking will be substantially affected.
Thus, the upper bound of this range might overestimate the impacts considering the level of
uncertainty associated with the majority of observations. Based on the total number of firms
estimated to be operating hi the Gulf of Mexico in the postcompliance scenario—435 firms
1-26
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minus 18 baseline failures,6 or 417 firms—these 0 to 12 potentially substantially affected firms
are 0 to 2.9 percent of the Gulf of Mexico segment of the oil and gas industry.
1.7 EMPLOYMENT AND COMMUNITY-1LEVEL IMPACTS
The EIA assesses employment and community-level impacts resulting from compliance
with the proposed effluent limitations guidelines for the coastal oil and gas industry.
1.7.1 Primary and Secondary Employment Losses
Compliance imposes a cost at both the well and the firm level, which might result in well
shut-ins and firm failures and thereby a loss In employment. Primary employment losses occur
only within the portion of the coastal oil and gas industry that discharges wastes. These job
losses are estimated from survey data on annual employment hours. Secondary impacts include
employment losses in other industries providing inputs to the coastal oil and gas industry and
other supporting industries. These impacts are assessed through multiplier analysis, which
measures the extent of impacts in other industries as a function of impacts in the primary
industry. The multiplier used in this analysis is based on input-output tables developed by the
U.S. Department of Commerce, Bureau of Economic Analysis (BEA). Primary and secondary
employment losses are summed to obtain the total impact on community employment levels
resulting from implementation of the effluent guidelines.
Employment losses are counted when a well shuts in (100 percent of the per-well
employment) and when a firm fails (100 percent of nonproduction employment). Total employee
hours lost because of well shut-in, or firm failure are expressed in full-time equivalents (FTEs)
assuming that 2,080 hours (52 weeks/year x 40 hours/week) equals 1 FEE. Table 1-5 presents the
results of primary employment losses in the baseline. The table shows that, before any
There are 5 baseline failures, plus 4 postanalysis baseline failures. These are multiplied by
two to extrapolate to all dischargers.
1-27
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compliance costs are incurred, 281 jobs are estimated to be lost, out of a total Gulf and Cook
Inlet employment of 6,197 workers (4.5 percent of total employment in the affected portion of
the industry), all occurring in the Gulf of Mexico region. (No baseline employment losses are
projected for Cook Inlet.) The baseline analysis predicts that secondary job losses will total 807
using the secondary employment multiplier of 2.86 estimated for the Gulf of Mexico region
based on BEA data. These baseline losses constitute an insignificant portion of national
employment and have a negligible impact on national-level employment rates.
Table 1-5 also presents postcompliance employment losses by region and by type of loss
for each of the regulatory options considered in this analysis for produced water and drilling
waste. Total employment losses associated with produced water options (not including Option
#1) are estimated to range from 101 FTEs for Option #2 (1.7 percent of combined Gulf of
Mexico and Cook Met employment) to 290 FTEs for Option #5 (4.9 percent of combined Gulf
of Mexico and Cook Inlet employment, which, postbaseline, is estimated to be 5,916 FTEs). The
selected produced water option (Option #4) combined with any drilling waste option are
associated with losses totaling 181 FTEs (or 3.1 percent of combined Gulf of Mexico and Cook
Inlet employment). Based on the multiplier of 2.86 percent for the Gulf of Mexico, total primary
and secondary losses will total 518 FTEs.
An additional employment impact will also occur. On average, in the baseline, wells are
expected to have a projected 15-year productive lifetime in the Gulf (in Cook Inlet, the change
in platform life is considered negligible). Under either Options #2 or #3 through #5 for
produced water, the productive lifetime drops to around 10 years. Thus, an estimated 1,561
FTEs will be lost hi 10 years rather than in 15 years. This loss is equivalent to a 3 percent
decline per year in employment versus'a 2 percent per year decline under the baseline scenario,
or in annual terms (i.e., lost FTEs discounted to the present and annualized), 337 FTEs per year.
This figure is considered a maximum. If wells are shut in in a pattern resembling a normal
distribution, a more realistic estimate would be less than 169 FTEs. This impact is not added to
first-year employment losses because these impacts occur, on average, about a decade hence.
Because employees have ample time to find alternative sources of employment, and natural
attrition might take care of the bulk of employment declines, these impacts are considered minor
(even when discounted) compared to first-year losses.
1-28
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1-29
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An increase in the community employment rate due to compliance with the regulation
equal to or greater than 1 percent is considered significant by EPA. This impact would
correspond to a considerable change in the community employment rate. .-Based on an "average"
county within the Gulf of Mexico coastal region (i.e., a county with average population and
employment rate), and assuming all losses occur within this one composite county, employment is
expected to decline no more than 0.3 percent. The decline in employment rate in any one
community in the Gulf of Mexico region, however, will be much less than this 0.3 percent.
Labor Requirements and Potential Employment Benefits
Firms will need to install and operate pollution control systems to comply with effluent
limitations guidelines for the coastal oil and gas industry. The manufacture, installation, and
operation of these systems will require use of labor resources. EPA analyzed each of the
components of direct labor requirements separately. The sum of the estimated requirements for
the three labor categories represents the estimated total direct labor requirement, and, thus, the
potential direct employment benefit, from compliance with the effluent guidelines.
As Table 1-6 shows, the labor associated with manufacturing the compliance equipment is
estimated to be up to 52 FTEs per year (depending on which drilling waste options are selected)
associated with the Gulf of Mexico and Cook Inlet operations (46 FTEs Gulf of Mexico and 5 to
6 FTEs Cook Inlet).
A total of up to 56 FTEs per year (51 FTEs in the Gulf of Mexico and 4 to 5 FTEs in
Cook Met) are associated with installing the compliance equipment. A total of up to 31 FTEs
per year (27 FTEs Gulf of Mexico and 1 to 5 FTEs Cook Inlet) will be required to operate the
equipment.
Summing the three components yields the total direct labor requirements for complying
with the proposed coastal oil and gas industry effluent guidelines as represented by the selected
regulatory options. On an FTE basis, the estimated total annual labor requirement is 124 FTEs
(Gulf of Mexico) and 10 to 15 FTEs (Cook Inlet), depending on drilling waste requirements, for
1-30
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TABLE 1-6
TOTAL ESTIMATED BISECT EMPLOYMENT GAINS:
GULF OF MEXICO AND COOK INLET REGIONS
Manufacturing
Installation
Operation
(annually)
Total direct
labor effects
Annual Labor Cost
With Option #1
Drilling Waste
$2,633,124
$3,146384
$1,625,155
$7,404,663
With Option #2
Drilling Waste
$2,698,986
$3,225,084
$1,664,505
$7,588,575
With Option #3
Drilling Waste
$2,698,986
$3,225,084
$1,798,160
$7,722,230
Annual Basis
Employment
Gains (FTEs)
51-52
55-56
28-31
134-139
1-31
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a total of up to 139 FTEs. This number must be offset, however, by the employment gains that
•will not occur as a result of the effluent guidelines. A total of 10 to 20 FTEs might not be added
to the labor force under the combined produced water and drilling waste pptions proposed
because of wells not drilled (and, thus, never produced). Thus, 119 to 127 FTEs might be added
as a result of the regulation. For simplicity, 119 FTEs gained is used to estimate net labor
effects.
In addition to direct labor effects, the coastal oil and gas industry effluent guidelines
might also generate labor requirements through the indirect and induced effect mechanisms,
thereby generating secondary employment. The secondary effects associated with an economic
activity are analyzed by using multipliers. Two multipliers were used—one for equipment and
installation employment 'gains and one for operating employment gains. The indicated aggregate
employment effects associated with the direct labor requirement of 119 FTEs would be 397 FTEs
under the highest impact scenario (Option #4, produced water, and Option #3, drilling waste).
1.73 Net Effect of Employment Losses and Gains
The primary employment gains (119 FTEs) are expected to partially offeet primary
employment losses (181 FTEs under all the combinations of the preferred produced water option
and the co-proposed drilling waste options). Thus, net primary losses might be 62 FTEs.
Primary and secondary gains of 397 FTEs are expected to offset partially the primary and
secondary loss of 518 FTEs estimated above. The net effect on employment therefore might be
121 FTEs lost. The net employment impact is negligible when compared to national-level
employment and will have no impact on national-level employment rates.
1.8 IMPACTS ON THE BALANCE OF TRADE, INFLATION, AND CONSUMERS
Although the costs and economic impacts of the BAT and NSPS regulations will fall
primarily on the coastal oil and gas industry including its employees, other secondary effects in
other sectors of the economy would also occur. The United States has recently entered a time
1-32
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when oil imports exceed total oil production. Unless domestic demand for oil is curbed, the
United States will continue to import a growing percentage of the supply needed to satisfy
domestic consumption. Under Option #4, for produced water (the selected option), and with
Cook Inlet meeting zero discharge of drilling waste, total lifetime production declines are only up
to 2.0 percent of total lifetime coastal production. This is a small percentage considering decline
hi domestic production is estimated to be occurring at 3 percent per year. The negative change in
the balance of trade expected from the rulemaking will not be significant compared to changes
caused by other factors.
The regulations can lead to higher costs to the operators. Because of the inability of the
companies to raise prices in response to increased costs, however, no substantial impacts on
inflation are likely from increased costs of pollution controls on coastal oil and gas effluents.
Therefore, this rulemaking will have no substantial distributional impacts, since consumers of oil
products will not be facing higher prices as the result of higher domestic producer costs.
1.9 REGULATORY FLEXIBILITY ANALYSIS
EPA guidelines require EPA Offices to perform Regulatory Flexibility Analyses (RFAs)
for regulations that have any effect on any small entities. An Initial Regulatory Flexibility
Analysis (IRFA) was performed in this EIA for the proposed effluent guidelines and standards
for the coastal oil and gas industry to determine their effect on small firms. The IRFA estimates
86 percent of the 435 firms in the survey universe are small firms.
Two measures are used in this EIA to determine whether disproportionate impacts are
occurring among small firms: the firm failure analysis and a screening analysis of impacts
measured as changes in equity and working capital. (This analysis is only performed for Gulf
firms; all firms in Cook Inlet are large.)
In Section Six, the EIA examines firm-level impacts by screening firms to determine
potential impacts on equity and working capital assuming that annual costs would be paid for
either through increased liabilities or by using working capital. Where annual costs exceed 5
1-33
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percent of either equity or working capital, the potential for significant impacts is considered in
more detail. The only firms in the sample considered in Section Six that are identified as
concerns are small firms. Most of these firms were not considered likely to fail, however, when
analyzed in more detail. Only six firms in the sample (representing 12 firms overall in the Gulf
of Mexico region) were further identified as possible firm failures. Out of the 354 small firms in
the estimated (postbaseline) survey universe, however, the 12 possible firm failures represent only
a maximum of 3.4 percent of small firms and only 2.9 percent of all Gulf coastal oil and gas
firms.
It is important to note that most coastal oil and gas firms in the Gulf coast region (as of
1996) will not be discharging wastes. Only 29 percent of the coastal oil and gas firms are
estimated to be discharging any produced water as of 1996. Thus, the typical small oil and gas
firm (represented as the median firm) is estimated to incur no compliance costs whatsoever.
Moreover, compliance costs as a percentage of the present value of net income at the median
small firm (as well as at the median large firm) in the coastal oil and gas industry will be zero,
even if net income declines slightly over time. Thus, the typical small coastal oil and gas firm
will not be disproportionately affected by the proposed effluent guidelines as compared to the
typical large coastal oil and gas firm.
1.10 IMPACTS ON NEW SOURCES
In most cases, the selected NSPS and PSNS regulations have been set equal to the
selected BAT options and, thus, are considered to pose no significant barrier to entry. Impacts
on new sources in Cook Inlet from the NSPS requirements for produced water, however, need to
be addressed. Based on the analyses performed for the Offshore Effluent Guidelines (which
continue to be relevant analyses for the Coastal Effluent Guidelines since the same financial
model was used in the offshore analysis to determine impacts on Cook Inlet platforms, which
were being considered for inclusion in the offshore subcategory), EPA concludes that impacts on
new sources in Cook Inlet are minimal and the NSPS requirements .should not pose significant
barriers to entry for two reasons: (1) declines in returns (measured as net present value and
internal rate of return) are very small and most likely will not affect the decision to undertake a
1-34
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new project (i.e., profitability of new projects will not be substantially affected by the regulation),
and (2) estimated impacts on new sources from NSPS requirements are not substantially greater
than those estimated for existing sources from BAT requirements;
1-35
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SECTION TWO
DATA SOURCES
2.1 INTRODUCTION
This EIA uses a number of sources of information, but primarily it uses the Section 308
Survey of the Coastal Oil and Gas Industry, which was undertaken exclusively to provide data
necessary for this rulemakmg. The coastal oil and gas industry is difficult to analyze using
secondary sources of information because it is an especially small subset of the U.S. oil and gas
industry and this designation is not used by any other federal or state agency or industry; so no
data have been collected under this definition. Moreover, this subset is an unusual subset
because most of the operations are conducted in shallow to relatively deep waters, although not
as deep as waters that are typical for offshore oil and gas industry operations. Unlike the
offshore oil and gas industry (which tends to have well-defined secondary source data), little to
no data specific to the wells in the coastal region are available (with the exception of Cook Inlet
and California).
The data that are available on the U.S. oil and gas industry tend to reflect either offshore
conditions (deep water) or onshore conditions. Many onshore or offshore parameters are not
likely to be representative of most coastal operations. The coastal subcategory does include
some wells that can appear similar to onshore wells; however, before the survey was undertaken, '
the number of operations that could be considered similar to onshore operations was not known
(it is not the major portion of coastal operations, however). Further, since very few multiwell
platforms operate in the coastal region outside Cook Inlet and California, and those that do have
fewer than four wells on them (ERG, 1994), few if any operations will resemble the offshore
industry operations.
Thus, secondary source information is used where necessary in this EIA, but mostly to
compare the coastal industry to the overall U.S. industry. Such sources include, among others,
the American Petroleum Institute's (API's) Basic Petroleum Data Book, Dun & Bradstreet
2-1
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statistics on financial indicators, and Oil and Gas Journal articles on price and production trends
in the United States. Additional primary sources of information include contacts within the
industry and in the key coastal region states and permit databases from Louisiana and Texas
covering wells and discharging produced water treatment facilities.
The first step in collecting data on the coastal oil and gas industry was to determine who
was operating in the coastal region and how many wells were involved. The key area of concern
was the Gulf of Mexico region with its many bays, harbors, bayous, lakes, rivers, and wetlands,
which form the key identifiers of potential coastal well locations. EPA determined that the only
way to identify the likely affected population in southern Louisiana and east Texas was to
identify the location of the wells in relationship to the various waterbodies in this region.
Section 2.2 describes this mapping effort and the creation of a location database, which
was used to identify a large portion of the affected operators in the Gulf of Mexico. Section 2.3
then describes how the identified operators and their wells were selected, sampled, and surveyed
in the Section 308 survey.
2.2 THE COASTAL MAPPING DATABASE
The primary source, of data used to determine the Section 308 survey universe was
developed using several computerized databases purchased and/or obtained from Tobin Surveys,
Inc. (Tobin), Petroleum Information (PI), the Louisiana Department of Natural Resources
(DNR), and the Texas Railroad Commission (RRC). Tobin compiles information on wells by
geographic location. Because of expense, the number of records (wells) that could be purchased
needed to be limited. A polygon of the Gulf of Mexico area was developed to identify well
locations that were considered likeliest to meet the definition of coastal (see Section 3.1 for the
definition of the coastal subcategory). This polygon, defined by longitudes and latitudes, was
provided to Tobin, which created a custom data set of wells. This data set included only wells
2-2
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completed after 1980.1 The total count of all wells in the polygon, both productive and
nonproductive, was 56,220 wells (ERG, 1992). The total number of wells for which data were
purchased from Tobin was 10,582. Tobin also supplied location maps of all wells in the polygon.
Four mapping phases were undertaken:
• Phase I—Wells were divided into offshore/federal waters, offshore/state waters,
and coastal/onshore categories. This task was performed by comparing well
locations with the "baseline," a line developed by Avanti Corporation that marks
the boundary of the territorial seas (see coastal definition in Section Three, and
Avanti, 1991). A total of 508 wells were identified as located in federal offshore
waters, 1,296 were identified as located in state offshore waters, and 8,778 were
identified as potential coastal wells (i.e., they were not in offshore waters).
• Phase II—To simplify the task of more precisely determining whether these 8,778
wells were located in coastal areas, nonproductive wells needed to be eliminated
from the analysis. Wells that were never produced—4,645 wells—were
eliminated, leaving 4,133 that had produced at some time.
• Phase m—Current productivity status could not be determined from Tobin data
because of infrequent, updates to this database. Thus, Pi's more frequently
updated database was used to eliminate currently nonactive wells from
consideration. The PI and Tobin databases were merged using the 10-digit API
number that is used to identify uniquely all oil and gas wells. Wells that were
currently productive as of September 1991 were identified as active wells in the
coastal database. A total of 2,710 wells were determined to be active.
» Phase IV—A number of the wells in Phase HI could be clearly identified as
coastal by their location in a body of water; however, hundreds of wells needed
further analysis to determine their status using wetlands maps. For Texas wells,
U.S. Fish and Wildlife Service (FWS) wetlands maps were used. The "unknown"
wells were plotted onto overlays of the same size and scale as the FWS wetlands
maps. Then the overlays were placed on the wetlands maps and each well was
manually identified and coded as to location (e.g., in a riverine, lacustrine, or
palustrine wetland or onshore) in the database. For Louisiana wells,
computerized wetland information had been compiled, and Louisiana State
1Pre-1980 wells were not identified or surveyed, although estimates of those wells likely to be
still active in the coastal region are estimated in Section Three. The decision to cut off data at
1980 was made because many wells completed prior to 1980 are likely to be no longer active and
the expense to obtain the data for and map these wells was prohibitive. The wells not surveyed
are limited to those that have not been completed or recompleted to produce from another zone
since 1980. Results of economic impacts, however, are extrapolated to these wells throughout
thisEIA.
2-3
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University was contracted to merge geographic information system (GIS) data
•with the longitude/latitude data from the Tobin database. These data were
subsequently merged back into the coastal database.
Table 2-1 shows the classification of wells completed since 1980 that were active as of
September 1991 and their location as a result of the mapping efforts in Louisiana and Texas.
Note that the onshore and unknown wells are, for the most part, also coastal, since most of the
polygon is within the Chapman Line, a line that was specified in the July 21,1982, Federal
Register (47 FR 31554) as defining the coastal subcategory in Louisiana and Texas regardless of
whether a well was located in a body of water (see Section Three for more details).
Following the mapping effort, and just before the Coastal Oil and Gas Questionnaire was
sent to coastal operators, data on current ownership was purchased from the Louisiana DNR and
Texas RRC (Louisiana DNR, 1993; Texas Railroad Commission, 1993). These new data were
merged into the existing database, using the 10-digit API number, to identify any changes in
ownership arid addresses of operators. Seventy wells were identified at this time as onshore and
not within the Chapman region and were dropped from the data set. The final result was a list
of 354 operators and 2,640 wells in the Gulf of Mexico coastal region.
23 THE COASTAL OIL AND GAS QUESTIONNAIRE
As part of effluent limitations guidelines and standards development, EPA conducted a
data collection effort for the coastal oil and gas industry—the 1993 Coastal Oil and Gas
Questionnaire. The Questionnaire was conducted under the authority of Section 308 of the
Clean Water Act (the federal Water Pollution Control Act, 33 USC Section 1318). It was used
to collect technical and economic information for use in developing the proposed effluent
guidelines for the coastal oil and gas industry. As discussed above, operators were identified
based on whether they operated wells identified as coastal subcategory wells.
EPA wanted up-to-date, accurate data to develop sound regulations, including
information about waste stream generation, treatment, and disposal; the costs of treatment and
disposal; and the financial status of the firms in the industry. Because of the varied data
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TABLE 2-1
PRESURVEY ESTIMATE OF NUMBER OF COASTAL WELLS BY LOCATION
Location
Inland bay/harbor
Estuarine
Lacustrine (in lakes)
Marine (wetland)
Onshore (Chapman)
Palustrine
(freshwater wetland)
Riverine
Unknown (assumed
coastal Chapman for
survey purposes)
Total
State
Louisiana
469
682
27
1
193
183
38
387
1,980
Texas
182
95
7
1
408
37
0
0
730
Total
651
111
34
2
601
220
38
387
2,710
Source: ERG estimates.
2-5
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required, the survey was designed to collect some information at the company level and collect
technical information at both the well level and treatment facility level. This task involved
conducting a census of the companies identified as operating wells in the coastal subcategory and
sampling the wells operated by these companies. Financial and some basic technical information
was required from each company; technical information on sampled wells and their respective
treatment facilities also was collected independently. Whereas some companies were required to
submit information on from one to many wells, others were not required to report on any wells
they operated in the coastal subcategory.
EPA identified 361 operators of oil and gas wells in the coastal subcategory—354
operators in south Louisiana and east Texas (see Section 2.2.), and 7 operators in Cook Inlet and
North Slope, Alaska. EPA identified a population of 3,623 coastal subcategory oil and gas wells
(2,640 Gulf of Mexico region wells and 983 Cook Inlet and North Slope wells). EPA stratified
the wells in the coastal subcategory by four factors:
A. Geographical location (Alaska or Gulf of Mexico)
B. Operator type (major, small independent, other)
C. Completion date (before 1990 or during/after 1990)
D. Water type (fresh or saline)
This population was then divided into three subpopulations. By dividing the wells into
subpopulations, EPA was able to conduct a census of wells within some categories and sample
wells in others. EPA conducted a census of all wells that were controlled by small operators
(i.e., operators with only one well in the coastal subcategory) and all wells on multiwell
structures, then sampled other wells in the population. The three subpopulations are:
A. Pretest—all 327 wells operated by 6 firms were enumerated in the pretest.
B. Census—179 wells were surveyed because either they were the only coastal wells
operated by individual firms or they were identified as potentially a part of a
multiwell platform.
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C. Sample—the remaining 3,117 wells were used as a sampling frame for selecting a
stratified random sample of 438 wells to be included in the questionnaire.
Survey results throughout the EIA are weighted according to the sampling plan. Wells
sampled from the third subpopulation received a weight equivalent to the ratio of total wells in
an individual stratum to wells sampled from that stratum, while wells in the census received a
weight of 1. Since all companies were surveyed, companies received a weight of one.
Overall, EPA conducted a census of the 361 companies identified as operating wells in
the coastal subcategory and surveyed 617 of the 3,296 wells remaining after pretest for the
questionnaire. For the regulatory proposal, EPA had results from 236 companies and 473 wells.
The current status of the respondent: companies is shown in Table 2-2 (SAIC, 1994).
As noted previously, one group of wells in Louisiana and Texas, the "pre-1980" wells, was
not captured in the Section 308 survey. Throughout the remainder of this EIA, results for the
Gulf of Mexico are extrapolated to this missing group as outlined in Section 3.33.1.
2.4 REFERENCES
Avanti Corporation. 1991. Delineation of the Baseline of Selected Coastal States. August 22.
Eastern Research Group, Inc. (ERG). 1992. Memorandum from Eric Sigler, ERG, to Ann
Watkins and Joe Ford, EPA. Status Update on Coastal Data Base. March 31.
Eastern Research Group, Inc. (ERG). 1994. Memorandum from Maureen Kaplan, ERG, to
Neil Patel, EPA. Stand-Alone Projects: ERG Multiwell Structures and Single-Well
Structures in the Section 308 Data. February 11.
Louisiana DNR. 1993. Well File and Operator Address File. Received by ERG from Louisiana
DNR, transmittal dated June 6, 1993.
SAIC. 1994. Draft Report: Estimation Procedures for the Coastal Oil and Gas Questionnaire.
April 12.
Texas RRC. 1993. Well Bore Data. Base Tape, P-4 Certificate of Authorization Tape, and P-5
Organization Report Tape. Received by ERG from Texas RRC, transmittal dated June
8,1993.
2-7
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TABLE 2-2
STATUS OF THE QUESTIONNAIRE RESPONSE
Status of Questionnaire
Company has data included in database
Company is out of scope (i.e., out of business, not a coastal operator,
never delivered, duplicate copy sent to the same company as another
survey)
Company will have data included in the database for the next round of
data analysis
Company is being contacted by EPA's Office of Enforcement
Total
Count
236
95
18
12
361
Source: ERG estimates.
2-8
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SECTION THREE
D«JUSTRY PROFILE
3.1 INTRODUCTION
The effluent limitations and guidelines for coastal oil and gas operations will affect only a
small portion of the overall U.S. oil and gas industry. For this subcategory of the industry, 40
CFR Part 435 defines "coastal" as "(1) any body of water landward of the territorial seas as
•
defined in 40 CFR Part 125.1(gg) [subsequently revised], or (2) any wetlands adjacent to such
waters." According to this definition., any well located in waters of the United States, or any
wetlands adjacent to a waterbody subcategory, is considered a coastal subcategory well. Most of
the activity in the coastal subcategory, however, is concentrated in and around the Gulf of
Mexico (i.e., the coasts of Alabama, Florida, Louisiana, and Texas); Long Beach, California; and
Cook Inlet and the North Slope of Alaska. Industry activity also was investigated in Mississippi
and the Mid-Atlantic region (i.e., along the coasts of Maryland and Virginia).
Investigations conducted as part of the EIA development process indicated that areas
beyond Gulf coastal Louisiana and Texas and Cook Inlet, Alaska, will not be significantly
affected by the proposed guidelines. These investigations included assessment of current industry
activities and practices in these regions as well as review of state regulations concerning the
discharge of wastes from oil and gas operations. Determinations about a region with coastal
subcategory activity that would not be affected by the guidelines are based on the following
findings (summarized in Table 3-1):
• Coastal Alabama. About 15 wells are thought to be operating in this area. As of
May 25,1994, however, when this region was designated part of the National
Pollutant Discharge Elimination System (NPDES), the discharge of drilling fluids
and cuttings has been prohibited. Also, a state law requires that produced fluids
be injected (ERG, 1993a; U.S. EPA, 1994a).
• Coastal Florida. About 41 producing wells in this region could be considered
coastal, operations and about 2 additional wells are drilled each year.
Nonetheless, all operators inject their produced water; reuse their drilling fluids or
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TABLE 3-1
STATUS OF COASTAL REGIONS OUTSIDE TEXAS, LOUISIANA, AND COOK INLET
Location
Mid-Atlantic coast
Alabama
Florida
Mississippi
California
North Slope
Number of
Producing
Wells
0
15
41
0
586
2,085
Annual Drilling
Activity
0
3-5
2
0
6-7
106
% Produced
Water Injected
NA
100%
100%
NA
100%
100%
% Drilling
Waste
Landfarmed or
Injected
NA
100%
100%
NA
100%
100%
NA = Not applicable.
Source: U.S. EPA, 1994a,b; ERG, 1993a.
3-2
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either inject them annually or leave them in a dry wellbore; and either dispose of
cuttings in reserve pits or haul them off site to a landfill (U.S. EPA, 1994a).
>
• Coastal Mississippi. None of the wells operating in Mississippi meet the
definition of coastal operations, and all well operators are required by state law to
inject their produced water (ERG, 1993a). No new wells are slated to be drilled
in the coastal region for the foreseeable future (U.S. EPA, 1994a).
• Long Beach, California. Oil and gas production in this area is restricted to four
manmade islands in San Pedro Bay (U.S. EPA, 1994a). As of 1993, 586 weUs
were operated in this area, and six to seven new wells were being drilled each
year. All produced water is injected, primarily for waterflooding (see Section 3.2),
and no drilling fluids or cuttings are being discharged.
• North Slope, Alaska. About 2,085 producing wells are operating on Alaska's
North Slope, and about 106 additional wells are drilled annually. No drilling or
production waste is discharged in this area (U.S. EPA, 1994b).
• The Mid-Atlantic Coastal Subcategoiy. Currently no oil and gas production or
drilling operations are being carried out in this region. Moreover, it is unlikely
that any such activity will be initiated within the next 15 years. Should any activity
commence, it is unlikely that operators would be allowed to discharge wastes,
according to state officials (ERG, 1994a).
The area in the.Gulf of Mexico that will be affected by this rulemaking includes coastal
Louisiana and Texas as shown in Figure 3-1. In response to litigation concerning the definition
of coastal, EPA further explained the definition in a Suspension of Regulation, 47 FR 31554
(July 21,1982). In that notice, EPA designated the Chapman Line. This line was established as
a series of latitudes and longitudes spanning the southern coast of Louisiana and the east coast
of Texas (see Figure 3-1). Thus, the Gulf of Mexico coastal region in Louisiana and Texas is
bounded by the territorial seas (the "baseline," as discussed in Section Two) and the Chapman
Line. The remainder of this EIA refers only to the Texas and Louisiana coastal regions as the
Gulf of Mexico region (although Alabama, Mississippi, and Florida are part of the Gulf region,
these states are excluded from the remainder of the analysis).
Also of concern is Cook Inlet, near Anchorage, Alaska, and the Kenai peninsula (see
Figure 3-2). This area and the Texas/Louisiana portion of the Gulf of Mexico are profiled in this
section of the EIA. The profiles cover wells, treatment facilities, and the firms operating in these
two areas. Section 3.2 presents a brief description of the process of oil and gas extraction,
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3-4
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Approximate Scala
(Statute MifesJ
Onttoro
S^arttion Faciay
Subset PlpsHrw
Figure 3-2. Map of Cook Inlet region.
3-5
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including how wells are drilled, how oil and gas is produced, and what wastes are generated
during these processes. Section 3.3 presents a general overview of the industry in the two key
regions. First, Section 3.3.1 compares the affected coastal industry to the .overall U.S. oil and gas
industry. Section 3.32 follows with a discussion of trends likely to affect the coastal oil and gas
industry. Section 3.33 discusses the characteristics of the wells and platforms in the Gulf of
Mexico and Cook Inlet and describes the types and nature of the firms owning and operating
coastal oil and gas production wells and facilities in these key coastal regions.
3.2 THE PROCESS OF OIL AND GAS EXTRACTION AND THE WASTES GENERATED
Two activities in the oil and gas extraction process generate the major portion of wastes
in this industry: drilling activities and production activities. These activities and the related
wastes are discussed in this section. The miscellaneous wastes, which are small volume wastes
associated indirectly with drilling or production operations, also are discussed. The major source
for the information in this discussion is U.S. EPA's Development Document for this rulemaking
(U.S. EPA, 1995).
3.2.1 Drilling Operations
The drilling operations of particular concern in this analysis are those performed in Cook
Inlet, Alaska. Currently all other drilling activities in the coastal subcategory do not discharge
drilling fluids and cuttings, either because of state or federal requirements or operator
preference.
The two types of drilling operations conducted as part of the oil and gas extraction
process are exploratory and developmental. Exploratory operations involve drilling wells to
determine potential hydrocarbon reserves. Once a hydrocarbon reserve has been discovered and
delineated, development wells are drilled for production. Although the rigs used for each type of
drilling can differ, the drilling process is generally the same.
3-6
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In the initial phases of exploration, shallow wells usually are drilled to discover the
presence of oil and gas reservoirs. Deeper wells subsequently are drilled to establish the extent
of a reservoir. Exploration activities are usualy of short duration, involve a small number of
wells, and are conducted from mobile drilling rigs.
In Cook Inlet, exploratory drilling is typically conducted from jackup rigs, which are
barge-mounted rigs with extendable legs that are retracted during transport. At the drill site, the
legs are extended to the floor of the waterbody, gradually lifting the barge hull above the water.
Some exploratory drilling has been performed in recent years in Cook Inlet as part of ARCO's
Sunfish field exploration (OGJ, 1994a).
Other than being conducted to begin extracting recently discovered reserves of
hydrocarbons, development drilling also is conducted to increase production or to replace
nonproducing wells on existing production sites. Since development wells tend to be smaller in
diameter than exploratory wells, less waste is generated.
Two commonly used types of drilling rigs for development drilling are the platform rig
and the mobile drilling units. In Cook Inlet, development wells often are drilled from fixed
platforms because once exploratory drilling has confirmed that an extractable quantity of
hydrocarbons exists, a platform is constructed at that site for drilling and production operations.
Frequently directional drilling is conducted to access different parts of a geological formation
from a fixed location such as a platform. This type of drilling involves drilling the top part of the
well straight down and then directing the welbore to the desired location. The last platform to
be constructed in Cook Inlet was built in the mid-1980s (Marathon/UNOCAL, 1994). Even with
the recent exploratory drilling in Sunfish, no additional construction of platforms is anticipated
(personal communication between Allison Wiedeman, EPA, and Jim Short, ARCO, May 9,
1994).
Rotary drilling is used in Cook Inlet. This method uses a rotating drill bit attached to the
end of a drill pipe, referred to as the "drill string." With this method, as the wellbore deepens,
the walls of the hole tend to cave in and widen; thus, periodically the drill string must be lifted
out so that a casing, which is a tube-shaped liner, can be placed in the hole. Cement then is
3-7
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pumped into the space between the casing and the hole wall to secure the casing. Each new
portion of casing must be smaller in diameter than the previous portion to allow for installation.
The process of drilling and adding sections of casing continues until final well depth is reached.
Rotary drilling relies on circulating drilling fluid to move drill cuttings (bits of rock) away
from the bit and out of the borehole. The drilling fluid, or mud, is a mixture of water, special
clays, and certain minerals and chemicals that is pumped "downhole" through the drill string and
ejected through the nozzles in the drill bit at high speeds and at high pressure. The jets of
drilling fluid lift the cuttings from the bottom of the hole and away from the bit so that the
cuttings do not interfere with the effectiveness of the drill bit. The drilling fluid circulates and
rises to the surface through the space between the drill string and the casing, called the annulus.
At the surface, the cuttings, along with silt, sand, and any gases, are removed from the drilling
fluid before the drilling fluid is returned downhole to the bit. The cuttings, silt, and sand are
separated from the drilling fluid by a solids separation process. This process typically involves
shaleshakers, desilters, desanders, and centrifuges (each removing sequentially smaller waste
particles from the drilling fluid). Some of the drilling fluid remains with the cuttings after solids
separation (Ray, 1979; Meek and Ray, 1980). In Cook Inlet, if the cuttings, silt, sand, and
residual drilling fluid do not contain free oil or other regulated contaminants, they are discharged
into the Inlet
Drilling fluid also can become contaminated, and thus, constitute a waste, during several
different stages of the drilling process. Additionally, drilling fluid can become waste if it cannot
be adjusted to provide the appropriate lubrication (lubricity) for drilling at different formation
pressures (which vary at different depths). When a drilling fluid no longer meets the
requirements for lubricity, density, viscosity, or gel strength, for example, a "mud changeover"
must be performed. The drilling fluid system replaced can become a waste at this stage if it is
not recycled or reused later in the drilling process.
Similarly, if drilling fluid solids cannot be controlled efficiently, dilution with fresh drilling
fluids might be necessary to reduce the solids content of the circulating drilling fluid system, in
which case the displaced drilling fluid can become a waste. The more recently developed solids
3-8
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control systems are much more efficient than in the past; thus, waste drilling fluid stemming from
the need to displace fluid that has become overloaded with solids is now less of a problem.
Most drilling fluid systems are water based. Although oil-based systems are less common
than they once were, some use of oil (or synthetic) additives is still necessary under special
circumstances, such as when performing directional drilling or when freeing a stuck pipe. Thus,
some portion of the drilling fluids used in Cook Inlet might not meet a more stringent toxicity
limit due to the occasional use of specialized fluids.
The most significant waste streams in Cook Inlet, in terms of volume and particular
constituents associated with drilling activities, are drilling fluids and drill cuttings. Drill cuttings
are generated throughout the drilling project, although higher quantities of cuttings are
generated when drilling the first few thousand feet of the well because the borehole is the widest
during this stage. In contrast, the largest quantities of excess drilling fluids are generated as the
project approaches final well depth. Most waste fluid is generated at completion of well drilling
because the entire drilling fluid system must be removed from the hole and the tanks used to
hold the drilling fluid. Some constituents of the drilling fluid can be recovered after completion
of the drilling, either at the rig or by the supplier of the drilling fluid. When drilling is
continuous, which can be the case on the multiwell Cook Inlet platforms, drilling fluid can be
reused to drill the next well in a series.
A much smaller waste stream; associated with the drilling process is drainage from deck
platforms during drilling, which can occur during rainstorms. In Cook Inlet, deck drainage is
combined with produced water (SAIC, 1994a).
3.2.2 Production Activities
Following the drilling process (in either the Gulf or Cook Inlet), the wells can begin to
produce reservoir fluids that consist of oil, natural gas liquids or condensate, and salt water
(sometimes dry gas is also produced). The salt water contains dissolved and suspended solids,
hydrocarbons, and metals and might contain small amounts of radionuclides. Portions of the salt
3-9
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water also can include enhanced oil recovery (EOR) fluids, which are gases or liquids injected
"downhole" to produce additional reservoir pressure. As hydrocarbons are produced, the natural
pressure in the reservoir decreases and additional pressure must be added to the reservoir to
continue production of the fluids. When a liquid is used, the process is called waterflooding.
EOR processes are divided into three general classes: thermal, chemical, and miscible
displacement. In the thermal process, generally steam is used to aid in removing hydrocarbons
form the geological formation. Chemical EOR processes use surfactants, polymers, and/or
caustics for washing oil from the formation and driving or displacing oil into the wellbore. In
miscible displacement, first kerosene or gas then water are used to dissolve then drive oil from
the formation. Typically EOR fluids are a part of the produced water stream.
As they surface, the gas and oil (including EOR fluids) are separated for further
processing and sale. Typically a series of vessels are used for the separation process. The major
waste streams associated with this process are produced water and, to a much lesser extent,
produced sand, which is, in part, made up of fine particles that are entrained with the oil and
produced water. More details on the equipment and processes used to separate and treat
produced water in both the Gulf and Cook Inlet are presented in Section 3.33.
3.23 Miscellaneous Wastes
Other wastes besides the drilling and produced water wastes discussed above also can be
generated during the productive life of a well. The most common miscellaneous wastes are
known as treatment, workover, and completion (TWC) fluids. Small volumes of production deck
drainage and domestic and sanitary wastes might also be generated. Deck drainage is generated
only if a platform is present. Sanitary and domestic wastes are generated only if toilet or washup
facilities are present orisite. Produced sand and deck drainage associated with drilling were
discussed above. This section therefore focuses on the processes that generate the major portion
of miscellaneous waste—treatment, workover, and completion processes.
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Treatment. Well treatment is the process of stimulating a producing well to improve oil
or gas productivity. Two basic methods of well treatment include hydraulic fracturing and acid
treatment. Hydraulic fracturing is typically used on sandstone, and acid treatment is generally
performed on formations of limestone or dolomite (Walk, Haydel and Associates, undated;
Wilkins, 1977). Hydraulic fracturing, in which a fluid is pumped into the formation under high
pressure, relies on inert materials known as proppants (e.g., sand, walnut shells, aluminum
spheres, glass beads) that remain in the formation to prop the channels open after the fluid and
pressure have been removed (Walk, Haydel and Associates, undated; U.S. EPA, 1987). This
method of well treatment is rarely used in the Gulf of Mexico.
Acid stimulation involves injecting acid solutions into the geological formation. The two
types of acid treatment used are acid fracturing and matrix acidizing. In acid fracturing, the acid
solution is injected under high pressure. The acid solution both dissolves the formation rock and
fractures it. Matrix acidizing uses low pressures to avoid fracturing. Other chemical treatments
sometimes used include treatment with organic solvents, such as xylene or toluene, to remove
paraffins or asphalts that block the wellbore.
Not all residuals from these well treatments become wastes. Many are recycled to be
used in other well treatment fluids. Nonetheless, some become part of the produced water
stream and'are subsequently discharged (such as in'Cook Inlet) or injected with produced water,
and some are disposed of separately from produced water.
Workover. Waste fluids can also be generated when a well undergoes a workover to
improve or restore productivity, repair or replace downhole equipment, evaluate the rock
formation, or abandon a well. Workovers are generally performed every 3 to 5 years (API, 1988,
1991). Responses to EPA's Section 308 survey indicate, however, that workovers in the Gulf of
Mexico occur once per year on average (SAIC, 1994b). Workovers generate some of same
wastes as those generated during well treatment and completion operations since some of the
operations are the same (e.g., stimulation, reperforation, casing repair, replacement of subsurface
equipment) (Walk, Haydel and Associates, undated; Acosta, 1981; API, 1988).
3-11
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Completion. Completion operations include the setting and cementing of the production
casing, packing the well, and installing the production tubing. All completion methods consist of
four steps: wellbore flush, production tubing installation, casing perforation, and wellhead
installation.
The initial wellbore flush involves injecting a slug of fluids into the casing. These
cleaning or preflush fluids can be circulated and filtered many times to remove solids from the
well and to minimize potential damage to the geological formation (U.S. EPA, 1992). Once the
well has been cleaned, a second completion fluid (i.e., a "weighting fluid") is injected. This fluid
maintains sufficient pressure to prevent the formation fluids from migrating into the hole before
well completion is finished.
Next, production tubing is installed inside the casing using a packer, which is placed at or
near the end of the tubing. The packer consists of pipe, gripping elements, and sealing elements.
When the tubing is in place, completion fluids are trapped between the casing and the
production tubing by the packer. These fluids, known as "packer fluids," provide long-term
protection against corrosion. Typically packer fluids are mixtures of a polymer viscosifier, a
corrosion inhibitor, and a high concentration salt solution (Gray, Darley, and Rogers, 1980).
These fluids can be removed during workover operations (Arctic Laboratories et al., 1983).
Following installation, the production tubing is perforated to allow hydrocarbons to flow
from the reservoir into the wellbore. For this step, a special gun is used to fire bullets or charges
that penetrate the casing and cement. Alternatively, a small perforated pipe can be hung from
the bottom of the casing (Baker, 1985; Radian Corp., 1977).
The final step calls for installation of the "Christmas tree," a device that controls the flow
of hydrocarbons from the well. When the valves of the Christmas tree are opened initially, the
completion fluids remaining in the tubing are removed before fluid from the formation begins to
flow.
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3.3 GENERAL OVERVIEW OF THE AFFECTED COASTAL SUBCATEGORY INDUSTRY
3.3.1 The Affected Coastal Subcategory Industry Compared to the U.S. Oil and Gas
Industry
The coastal subcategory is a small fraction of the overall U.S. oil and gas industry. Since
much of the subcategory is already achieving zero discharge, the portion of the coastal
subcategory that will be affected by the effluent guidelines is an even smaller fraction. Table 3-2
presents information on production, number of establishments, and number of wells in the
affected coastal subcategory industry as a portion of the U.S. oil and gas industry. The estimates
specific to the Gulf (Texas and Louisiana only) in this table are derived from the Section 308
survey and adjusted for wells that were completed prior to 1980 (see Section Two). Thus, the
number of wells shown here are greater than the number in the Section 308 survey universe (see
Section 3.33 for a discussion of how the number of "pre-1980" wells was estimated). As the
table shows, the affected portion of the coastal subcategory is estimated to produce (in 1992)
56.4 million barrels (bbls) of oil and 782.4 Mcf (million cubic feet) of gas, which is only 2.1
percent of total U.S. oil production and 3.5 percent of U.S. total gas production. Oil production
from this subcategory alone is equivalent to only 2.5 percent of total foreign oil imports.
The value of annual oil and gas production in the affected coastal subcategory (i.e., the
Louisiana/Texas portion of the Gulf and Cook Inlet) is estimated to be $1,891.1 million (1992),
which is 2.5 percent of the value of total U.S. production. The affected portion of the
subcategory is estimated to employ 6,167 employees, or 3.4 percent of the total U.S. oil and gas
production workforce. The number of establishments (firms) is estimated at 440, which is 3.4 to
6.0 percent of the numbers of establishments in the comparable portion of the U.S. industry (see
footnote to Table 3-1). The total number of wells in the affected portion of the industry is
estimated to be 4,912, which is 0.6 percent of the total number of producing wells in the United
States. A more detailed analysis of wells, treatment facilities, and firms in the affected coastal
region is discussed in Section 3.3.3.
3-13
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3-14
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3.33. Trends in the Affected Coastal Subcategory f
Because the Section 308 survey did not collect more than 1 year's data, trends exclusive
to the affected coastal subcategoiy could not be described. Nonetheless, the trends of greatest
concern—the rate at which production is expected to decline with time and the expected track of
the wellhead price of oil—can be expected to follow general industry trends to some extent.
These two trends are central to several important assumptions used in this economic
analysis. Assumptions about the rate of decline of oil production can vastly change the outcome
of analyses that predict the economic viability of a well or platform, as can assumptions about
the price of oil or gas. The economic life of a well or platform will be lengthened as decline
rates fall or as prices rise; conversely, the economic life will be shortened as decline rates rise or
as prices fall.
Data on the rate of decline of oil production at individual wells are available, both for
Gulf of Mexico and for Cook Inlet wells. An analysis of data used to determine the location of
wells in the Gulf coastal region (see Section Two), for instance, indicates that Gulf of Mexico
well production tends to decline at a rate of 12 to 15 percent per year (ERG, 1992).
Information provided by Cook Inlet operators (Marathon/UNOCAL, 1994) indicates that the
typical decline rate for wells in that area is about 8 percent per year. The economic model of
the Cook Inlet platforms (discussed in Section Five) is used to generate the expected lifetime
production (i.e., the total amount of hydrocarbons that can be produced given the economic
profile of the platform, such as costs of production, price of oil, etc.) in Cook Inlet based on this
decline rate and the number of wells and recompletions expected to be undertaken in the Inlet.
This expected total lifetime production of all platforms is estimated to be 198.1 million barrels of
oil equivalent (BOE)1 with a net present value of $417.2 million.
For the Gulf of Mexico, the economic model is not used to determine lifetime production
for the entire region. Rather, a decline rate is factored into current levels of production to
JTo compute barrels of oil equivalent, a volume of gas is converted to an equivalent barrel of
oil on the basis of Btu content, then added to oil production.
3-15
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compute a lifetime production estimate, which is a more simplistic approach than that used for
the analysis of Cook Inlet. Use of a 12 to 15 percent decline rate associated with individuals
wells, however, will overstate declines for a region, since wells are constantly being drilled to
replace or augment current production.
According to recent projections (OGJ, 1994b), overall production will be declining in the
United States at a rate of about 3 percent per year from 1993 to 2000. Given that the Gulf of
Mexico coastal area in Louisiana and Texas is a mature area, production in this region could be
declining at a higher rate than the overall U.S. rate. Nonetheless, the two decline rates, the 3
percent national estimate and the 15 percent well-specific estimate, can be used to bound the
estimate of the decline rate in the Gulf of Mexico. A 30-year horizon was used to compute
lifetime production in the Gulf (if declines are closer to 3 percent per year, however, a 30-year
horizon might be somewhat short and could understate lifetime production). Lifetime
production can be computed in a manner similar to computing the net present value of a stream
of income. Based on the assumption that oil today is worth more than oil tomorrow (as a dollar
today is worth more than a dollar tomorrow), the net present Value" in terms of BOE was
calculated using the present (1992) estimated production of 159.2 million BOE and both the high
and low estimate of potential decline over the 30-year horizon. This calculation results in a total
lifetime production estimate for the Gulf of Mexico ranging from 692.5 million BOE to 1,3912
million BOE.2
With production declines, the revenues, employment, and other indicators of an industry's
vitality also will tend to decline, although the number of firms operating in the Gulf of Mexico
might not decline for a while. The largest well owners in the region, large independents and
integrated oil companies ("majors"—see Section 3.33.3), are leaving the region because other
investments (primarily foreign) are proving more profitable. Thus, they are selling their
properties to local owners, who tend to be small and own just a few wells. Indeed, many (about
40 percent) of the operators in the Gulf of Mexico own only one coastal well completed after
2Since the model presents lifetime production in this present value manner, it was necessary
to use the same approach for comparison purposes. Using either this present value approach or
a straight additive volume approach will produce the same results, proportionately, in the
analysis.
3-16
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1980 (although they might own other onshore properties and pre-1980 wells) (ERG, 1993b).
Thus, the trend in the Gulf coastal region is one toward a less highly concentrated industry3 with
many very small firms (nearly 40 percent of the Gulf operators employ only 0 to 9 employees;
see Section Nine).
The price of oil has been assumed to be constant in this EIA. This assumption is
consistent with current forecasts of oil prices (OGJ, 1994c), which indicate that oil prices are
rising at about the same pace as inflation (i.e., the real price of oil is not expected to increase
through the rest of this decade). Forecasts, however, cannot anticipate major oil shocks, and
taking into account such exogenous factors is beyond the scope of this analysis. In general, if oil
prices increase substantially, regulatory impacts will tend to become proportionately smaller.
Conversely, if oil prices decrease substantially, impacts could become proportionately larger,
although baseline well shut-ins and firm failures could substantially alter the entire analysis.
333 Detailed Discussion of Wells, Facilities, and Firms
3.33.1 Wells and Platforms in the Coastal Region
According to estimates from the Section 308 survey, there are currently 2,548 producing
Gulf coastal wells in coastal Texas and Louisiana (not all wells in the original survey universe of
2,640 wells—see Section Two—were found to have been productive in 1992). As discussed in
Section Two, however, the survey universe of Gulf coastal wells did not include wells completed
prior to 1980 or wells within a few very small sections of the Louisiana/Texas coastal region as
defined by the Chapman Line (see Figure 3-1). Figure 3-3 shows the area—"the polygon"—for
which well information was purchased from Tobin Surveys, Inc., in relation to the Chapman Line
(see Section Two). Further analyses were performed to determine the number of pre-1980/other
wells estimated to be currently producing. Two approaches were undertaken. In the first case
only the pre-1980 wells could be addressed (ERG, 1992). In this approach, the number of total
3A less highly concentrated industry is an industry in which many firms have a very small
market share, in comparison to a highly concentrated industry where very few firms have the
major portion of the market share.
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wells ever drilled in the polygon (see Figure 3-3) is known and the survival rates of productive
wells from 1980 to 1990 are also known. Based on the total number of pre-1980 wells in the
polygon estimated to have been productive at some time (26,861 wells) and a decline rate
developed as an exponential function (ERG, 1992), the total number of estimated pre-1980 wells
could be determined The decline rate equation leads to an estimate of a survival rate of 9.67
percent for all pre-1980 wells (i.e., 9.67 percent of ever-productive pre-1980 wells are estimated
to be currently productive). Applied to the total number of one-time productive pre-1980 wells,
an estimate of 2,597 currently productive pre-1980 wells is derived. This approach would miss
both pre-1980 and newer Chapman wells not captured in the polygon, although it could include
noncoastal pre-1980 wells in areas of the polygon not within the Chapman Line.
The second approach uses the number of known discharging treatment facilities (see
Section 33 below) combined with the number of discharging treatment facilities that were
estimated using the Section 308 survey. The number of discharging facilities estimated using
survey data is 202 facilities. Known permitted facilities in 1992 total 325. Thus, a little over a
third of discharging facilities were not captured in the survey. The average number of wells as
reported in the Section 308 survey served by discharging facilities (735 wells per facility) was
used to calculate the total number of discharging wells (735 x 325 facilities = 2389 wells). It
was also assumed that nondischarging facilities were missed by the survey in the same
proportions as discharging facilities since no information to the contrary is known; thus, the 328
nondischarging facilities estimated using the survey were extrapolated to 528 facilities. According
to the survey, nondischarging facilities serve 433 wells; thus, the total number of nondischarging
wells is estimated to be 2,286, for a total of 4,675 coastal wells (2,389 discharging wells plus 2,286
nondischarging wells). The difference between the estimated number of wells in the survey
(2,548) and the 4,675 estimated as above should be the number of pre-1980 wells and wells that
were missed within the Chapman Line. This estimate is 2,127 wells (of which most are
considered likely to be pre-1980 wells). The predicted number of wells using the decline rate
compares reasonably well to the number of wells estimated using the second approach.
*
The total number of Louisiana/Texas Gulf coastal wells is, thus, estimated to be 4,675.
This number is used as the 1996 baseline according to the assumption that approximately the
same number of wells will go into as out of service between 1992 and 1996. A total of 686 wells
3-18
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3-19
-------
drilled per year is estimated based on the Section 308 survey. (This estimate was not adjusted
because the majority of the "missed" wells are thought to be pre-1980 wells and, thus, the
"missed" discharging facilities might be serving pre-1980 wells predominantly. Therefore, this
"missed" group is not likely to be associated with much drilling activity.)
Consequently, hi 1992, based on an estimated 2,389 discharging wells and a total
estimated population of 4,675 coastal wells in the Gulf of Mexico region, 51 percent of Gulf of
Mexico wells are estimated to have been discharging. In 1996 this proportion will be
considerably less. According to Section 308 survey results,4 when facilities that are predicted to
cease discharging in 1996 are considered, only 1,588 productive wells (approximately 34 percent
of Gulf of Mexico coastal wells estimated to be productive in 1992) will be continuing to
discharge. See Section Five for a detailed discussion of how this estimate of 1,588 discharging
wells was determined.
The typical Gulf of Mexico well produces both oil and gas. A total of 7 percent of Gulf
coastal wells are gas only, 9 percent are oil only, and 84 percent produce both oil and gas (SAIC,
1994c). The average gas-only well produces 970 cubic feet of gas per day, while the average oil-
only well produces 16 barrels per day (bpd) of oil and the average gas and oil well produces 484
cubic feet of gas per day and 36 bpd of oil (SAIC, 1994d). Total production in the Gulf of
Mexico is estimated to be 42.8 million bbls of oil and 653.7 Mcf of gas, or 159.2 million BOB
annually (1992).s
Unlike the offshore subcategory for Cook Inlet, few Gulf of Mexico region wells are
located on multiwell platforms. The few multiwell platforms operating in the Gulf coastal area
•These results required additional adjustments for pre-1980 wells that are discussed in detail
in Section Five. These additional adjustments stem from the fact that the facilities that continue
discharging might disproportionately serve pre-1980 wells.
5This estimate includes the 1.61 factor for pre-1980/other wells. Note that this approach
might overstate total production because pre-1980 wells probably produce less on average per
day than wells drilled after 1980. Due to lack of data, however, it is assumed that production is
similar. If production levels are actually much less from these wells when the regulation is
promulgated than the survey wells, the number of wells estimated to be shut in immediately
might increase, but the proportion of total production lost would be reduced.
3-20
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appear to have less than four wells on them (ERG, 1994V). Thus, the key unit of analysis in the
Gulf of Mexico for determining production loss and economic life is the well. As discussed
.$<
below, when multiwell platforms are the rule, the platform becomes the key unit of analysis.
Given the typical single-well nature of the Gulf of Mexico region, well-based parameters are used
to model the economic viability of Gulf oil and gas production activities but the platform is the
key unit of analysis for Cook Inlet (see Section Five for key parameters for both Gulf wells and
Cook Inlet platforms).
Platforms in Cook Inlet
There are 15 platforms located in Cook Inlet, Alaska. Two of these platforms are
currently shut in (Spark and Spur—both owned by Marathon/UNOCAL), but drilling plans have
been developed for one platform (Spark). Thus, 14 platforms are considered operational or
potentially operational in Cook Inlet. A total of 237 wells are currently producing on these
platforms. Table 3-3 lists the platforms, the number of wells on each platform, and the
owner/operator of the platform. As shown, there are 208 oil wells and 29 gas wells in Cook
Inlet. Total annual production in 1993 was 12.9 million bbls of oil and 120.5 million Mcf of
marketable gas (AOGA, 1993). Total lifetime production (using the production loss model
under baseline assumptions—see Section Five) is estimated at 198 million BOE. Over a period
of 7 years, a total of 36 new wells are planned to be drilled and 22 recompletions are expected to
be performed (see Section Four for a detailed drilling schedule by platform).
A potential area of development in Cook Inlet is the Sunfish Field, which is located in
the North Upper Cook Inlet. At this time, the field has not been brought into production, and
discussions with industry (personal communication between EPA and ARCO, May 9,1994)
indicate that it is unlikely that a platform will be constructed to develop this field because of
disappointing exploration results.
3-21
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TABLE 3-3
PLATFORMS, OPERATORS, AND WELLS IN COOK INLET
Platform
King Salmon
Monopod
Grayling
Granite Point
Dillon
Bruce
Anna
Baker
Dolly Varden
Spark
Steelhead
Spurr*
SWEPI "A"
SWEPI "C"
Tyonek "A"
Operator
UNOCAL
UNOCAL
UNOCAL
UNOCAL
UNOCAL
UNOCAL
UNOCAL
UNOCAL
Marathon
Marathon
Marathon
Marathon
Shell
Western
Shell
Western
Phillips
No. of
Active
Oil
Wells
19
29
24
11
10
11
20
11
24
0
3
0*
22
24
0
No. of
Active
Gas
Wells
1
0
2
0
0
0
0
1
1
0
11
0*
1
0
12
Oil
Production
(bpd)
4,100
2,000
7,000
4,300
0
600
2,300
1,000
6,500
0
1,800
0
2,700
2,400
0
Gas
Production
(Mcf)
Plat, use
Plat, use
Plat, use
Plat, use
0
Plat, use
Plat, use
Plat, use
Plat, use
0
165,000
0
Plat, use
Plat, use
165,000
Discharge
Location
Trading
Bay
Trading
Bay
Trading
Bay
Granite
Point
Platform
Platform
Platform
Platform
Trading
Bay
Granite
Point
Trading
Bay
Granite
Point
E. Foreland
E. Foreland
Platform
*Spurr is considered completely nonactive in this EIA.
Source: U.S. EPA, 1995; EPA, 1994b.
3-22
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3.333 Produced Water Treatment Facilities in the Coastal Region
Facilities in the Gulf of Mexico
A separation, or production, facility consists of the treatment equipment and storage
tanks that process the produced fluids. Production facilities can be configured to service one
well, or as central facilities that service multiple satellite wells, also known as tank batteries or
gathering centers. In 1992, according to permit databases provided by the Louisiana DEQ and
the Texas RRC, 325 produced water separation facilities were discharging in the Gulf coastal
region (EPA, 1995). Based on compliance schedules set up by Louisiana DEQ, court-ordered
requirements, and results of the Section 308 survey (which asked respondents whether they
would be discharging in 1996), facilities were removed from the list of dischargers to create a list
of facilities expected to be discharging in 1996. A maximum of 216 facilities6 are expected to be
discharging in 1996 (SATC, 1994e). The total number of nondischarging facilities in the Gulf of
Mexico region is estimated to be 528 in 1992.7 Thus, in 1996, only a little over one-quarter or
fewer of the produced water facilities (total 853) in the Gulf coastal region are expected to be
discharging, assuming the 109 facilities expected to cease discharging switch to injection or
commercial disposal.
Unlike other industries, wastewater generation in the oil and gas industry is not
proportionate to the quantity of materials processed. Produced water can constitute from 2 to 98
percent of the fluid production at a given facility. In general, the proportion of hydrocarbons to
produced water tends to be high during the initial production phase and decreases as
hydrocarbons are depleted. Thus, any regulation affecting the cost of produced water disposal
will tend to affect the older, more marginal fields more than the newer developmental projects.
is total does not account for wells that might shut in for reasons of economics unrelated
to the effluent guidelines between now and 1996, causing additional facilities to cease
discharging.
7TMs number is derived from the results of the Section 308 survey, adjusted by a factor of
1.61 to account for potentially missing facilities (see discussion above in Section 3.33.1).
3-23
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The average produced water discharge rate from the Gulf of Mexico is 1,923 bpd for
facilities that inject produced water and 2,069 bpd for facilities that discharge produced water
(SAIC, 1994f). As noted in Section 333.1, the typical discharging facility serves about seven
wells, whereas the typical nondischarging facility serves approximately four wells. This difference
might arise because with very low costs of disposal (typical of discharging facilities), marginal
wells can be operated economically for a longer period of time, leading to more wells being
served per facility at discharging facilities.
Currently, produced water treatment facilities in the Gulf of Mexico are designed to meet
best practicable technology (BPT) requirements, which restrict the oil and grease concentrations
of produced water to a maximum of 72 mg/L for any one day and to a 30-day average of 48
mg/L. Technologies and practices used to achieve this level of control include:
• Equalization (surge tank, skimmer tank)
• Chemical addition (feed pumps)
• Oil and/or solids removal
" Gravity separators
• Flotation
• Filters
• Plate coalescers
• Filtration prior to injection
• Subsurface disposal (injection)
The typical Gulf coast discharging facility uses gravity separators, which are tanks large
enough to store oil and water mixtures for a sufficient length of time to allow the mixture to
separate. Chemicals might be added to hasten or augment the separation process. At separation
facilities where produced water is injected, the produced water is typically filtered prior to
injection. Although used in the Gulf, gas flotation is not used widely enough in coastal
operations to be considered a typical BPT process. Subsurface injection, however, is more
3-24
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frequently used in coastal areas, as the number of nondischarging facilities in the Gulf coastal
region reflects.
Facilities in Cook Inlet
Three land-based and five platform-based separation/treatment facilities operate in Cook
Inlet. About 98 percent of all produced water is treated and discharged from the three land-
based facilities (primarily the Trading Bay facility). Produced water is generated at a rate of
about 127 thousand barrels per day (U.S. EPA, 1995). One platform and one land-based facility
currently use gas flotation (in addition to skim tanks; which is a type of gravity separator). Most
other facilities use skim tanks only, or a combination of skim tanks and corrugated separators
(Table 3-4).
3.33.3 Oil and Gas Firms Operating in the Coastal Region
The expenditures required to comply with the effluent limitations guidelines for the
coastal oil and gas industry will be financed by coastal firms and their investors. Before assessing
the impact of the effluent guidelines, it is useful to evaluate the current financial condition of
these firms, both generally and in comparison with the overall domestic oil and gas industry. The
firms in the Gulf of Mexico are discussed first. Information on the corporate structure of the
firms involved in oil and gas production in this region is presented and the results of ratio
analyses and the relative health of these firms are discussed in terms of profitability, leveraging
ability, and other factors. The financial condition of known dischargers is also compared to the
financial condition of the coastal operators overall.8 The same type of financial information is
then presented for the Cook Inlet operators.
all dischargers can be identified in the survey because not all wells were surveyed. Only
when a discharging well was surveyed can an operator be identified conclusively as a discharger.
Names of operators on discharge permits are also not always an identifier because some
operators are doing business under several different names and sometimes facilities might have
been sold but the permit database has not yet been updated with the new operator name.
3-25
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TABLE 3-4
PRODUCED WATER TREATMENT FACILITIES IN COOK INLET
Facility Name
Operator
Average
Produced Water
Volume (bpd)
Discharge
Location
Treatment Type
Platform-Based Treatment Facilities
Dillon
Bruce
Anna
Baker
Tyonek "A"
UNOCAL
UNOCAL
UNOCAL
UNOCAL
Phillips
0*
160
1,500
30
170
Platform
Platform
Platform
Platform
Platform
Skim tanks
Skim tanks
Skim tanks
Skim tanks
Skim tanks, gas
flotation
Onshore Treatment Facilities
Granite Point
Trading Bay
E. Foreland
UNOCAL
Marathon
Shell Western
300
121,243
3,300
Spark platform
Outfall
Outfall
Skim tanks
Skim tanks, gas
flotation,
settling pits
Skim tanks,
corrugated
separators
*Dillon was not discharging at the time of EPA's analysis. Recent information indicates it is
currently discharging. During 1991, the discharge volume was 2,650 bpd.
Source: U.S. EPA, 1995.
3-26
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Firms Operating in the Gulf of Mexico
Gulf coastal petroleum producers can be divided into two basic categories. The first
consists of the major integrated oil companies. These companies are characterized by a high
degree of vertical integration (i.e., their activities encompass both "upstream" activities—oil
exploration, development, and production—and "downstream" activities—transportation, refining,
and marketing). The second category of coastal producers are independents. The independents
are engaged primarily in exploration, development, and production of oil and gas and are not
typically involved in "downstream" activities. Some independents are strictly producers of oil and
gas, while others maintain some service operations, such as contract drilling and well servicing.
The major integrated oil companies are generally larger than the independents. As a group, the
majors generally produce more oil and gas, earn significantly more revenue and income, have
considerably larger assets, and have greater financial resources than the independents. In
general, majors are relatively homogeneous in terms of size and corporate structure. All majors
are considered large firms under the Regulatory Flexibility Act (RFA) guidelines and all
generally are standard corporations (rather than S corporations, limited partnerships, or other
alternative structures) (see Section Nine).
Producing companies vary in their range of products. In the early 1980s, due to cash
surpluses and diminishing oil reserves, many oil companies, and particularly the majors,
diversified into other areas such as mining and development of alternative nonpetroleum energy
sources (U.S. EPA, 1993).
Independents can vary greatly by size and corporate structure. Larger firms tend to be
corporations; smaller firms tend to be S corporations, limited partnerships, sole proprietorships,
and other types of structures.9 Because of the differences in the tax code, the independents
need to be organized by corporate type to accurately assess profitability (most firms that fall into
the "other" corporate structure category do not pay corporate taxes, thus, net income figures are
effectively pretax).
9S corporations are corporations that have elected to be taxed at the shareholder level rather
than the corporate level under Subchapter S of the Internal Revenue Code. The other
alternative structures also allow individual owners rather than the corporation to be taxed.
3-27
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In general, 1992 and the preceding few years were hard ones in the U.S. oil and gas
industry (OGJ, 1992). Mergers, acquisitions, consolidations, and liquidations were common in
the years preceding 1992; the Oil and Gas Journal's OGJ 400 was cut to 300 firms in 1991 (OGJ,
1991). OGJ cites periodic slumps in the prices of crude oil, natural gas, and petroleum products,
and higher costs of operations due to environmental requirements as the driving force behind
these reductions in the numbers of firms. As the results of the financial analysis of coastal firms
show, 1992 also was not a good year for coastal firms and perhaps was somewhat harder on these
firms than on the U.S. oil and gas industry as a whole. In general, 1993 was a somewhat better
year among the OGJ 300 with a 75.5 percent increase in net income from 1992 to 1993 (OGJ,
1994d), although some of this improvement is attributable to accounting changes. Whether
possibly both conditions were also felt by coastal firms is, however, not known.
A total of 213 Gulf operators provided enough financial data in the Section 308 survey to
construct a profile of operators. These operators were divided into small and large operators on
the basis of the RFA guidelines, which define a small oil and gas firm as one with 500 or fewer
employees (Section Nine of this EIA presents financial information on firms under more detailed
size breakdowns). Of the 213 operators that are used in this analysis, a total of 181 of these
operators (or 85 percent) are small according to RFA guidelines; 32 (15 percent) are large.
Most of these large operators (22 out of 32, or 69 percent of large operators in this group) are
major oil companies as defined by the Pennwell Directory (Pennwell, 1994) (see Table 3-5).
Most independent oil companies in the analysis group are small (90 percent). Of the 181
small independents, only about a third have a standard corporate structure. The remaining two-
thirds do not report corporate taxes.
Several analyses were performed to determine financial status of the Gulf firms. Medians
were determined for the key financial variables of interest, since industry benchmarks are
computed on the basis of medians and quartiles. All benchmarks are from Dunn & Bradstreet
(1993) for SIC 1311 Petroleum and Natural Gas unless otherwise noted. A brief definition of
the measures of financial health used to characterize the Gulf coastal firms are as follows:
3-28
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• Total Assets. The sum of all liquid (cash-type) and nonliquid (e.g., real estate)
assets of the company.
• Equity. Total assets minus total liabilities, or the firm's net worth.
• Profitability
Return on Assets (ROA): Net income over total assets. The median for
the publicly held oil and gas production industry as a whole was 3.5
percent in 1992. The lowest quartile was -1.3.
Return on Equity (ROE^: Net income over equity or net worth, which is
total assets minus total liabilities. The median for the publicly held oil and
gas production in industry was 6.2 percent in 1992. The lowest quartile
was -2.0.
• Leverage
Interest Coverage Ratio CICRV Earnings before interest payments and
taxes over interest expense, which measures the ability of a company to
meet interest and principal payments on debt. Most analysts like to see an
ICR of 3 or more (Johnston, 1992).
• Liquidity
— Working Capital: Current assets (cash-type assets) minus short-term debt
(e.g., credit-line debt).
— Current Ratio: Current assets over current liabilities provides a measure
of working capital that can be compared to industry benchmarks. For this
industry the median is 1.4. The lowest quartile is 0.9.
Benchmarks are useful in showing how healthy a firm or a subset of an industry is in
comparison to the industry as a whole. In general, if the segment is at the median or above, it
can be considered relatively healthy in comparison to the industry. Somewhat below the median
would be considered weak but potentially acceptable financial health, while below the lowest
quartile (only a quarter of firms in the industry have a measure that low or lower), financial
health can be considered poor. If the financial health of the entire industry is poor relative to all
industries, even better performing firms might be considered in poor financial health, however.
As Table 3-5 shows, the majors tend to have the greatest assets and equity. "Other" (not
standard corporations) small firms tend to have the lowest assets and equity. Surprisingly, the
3-29
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capital is quite low, and the current ratio is less than one.
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population), coastal costs as a percentage of total operating costs are substantially higher—22
percent of total costs are incurred from coastal operations. Two conclusions might be drawn
from this observation (assuming that this is a statistically significant difference). First,
discharging coastal operations might be very marginal in many instances. Second, and more
importantly, loss of coastal revenues (should wells be shut in) from discharging coastal operations
might not result in major impacts because the typical discharging firm appears to maintain
potentially much more profitable operations outside the coastal region that generate the bulk of
total revenues.
Because many of these firms will not be discharging in 1996, it is not clear that this same
result would apply to those who continue to discharge. The financial status of many of the firms
that will continue to discharge in 1996 (including the proportion of coastal revenues and costs to
total revenues and costs, where relevant) is investigated in detail in Section Six.
Tables 3-9 and 3-10 investigate the profitability of the coastal firms in terms of ROA and
ROE. These indicators of financial health are typical of those used by investors to determine
whether to make an investment in a firm. Another measure of financial health is the interest
coverage ratio. This ratio is used by lenders (or bondholders) to determine the creditworthiness
of a firm. All of these measures are useful for determining whether a firm might be able to
make the capital investment (either through equity or borrowing) in pollution control equipment
necessary to meet the proposed effluent guidelines. Again investors or lenders often compare a
firm's ratios to industry benchmarks, as noted above.
As Table 3-9 shows, ROA and ROE reflect the relatively poor year for the industry.
Moreover, medians for most categories of coastal firms (except the major's ROE) fall below
medians on ROA and ROE (3.5 percent and 6.2 percent, respectively). All categories, however,
are well above the lowest quartile. Even the firms that do not incur corporate taxes (and thus
whose financial ratios are not directly comparable to the Dun & Bradstreet benchmarks) can be
assumed to have on average at least positive returns (unlike the lowest quartile Dun &
Bradstreet group, which showed returns of -1.3 on assets and -2.0 on equity). The interest
coverage ratio, which is. below the benchmark of 3 for all categories of coastal firms (except for
the majors, which have a median of 3.0), indicates that the ability to borrow among this group
3-35
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might be restricted. This result means that measures of these firms' ability to use their equity
and working capital could be very important to this analysis. As a whole, the coastal firms
appear to be somewhat weak financially, but not, on average, among the weakest groups in the
industry.
Table 3-10 presents ROA, ROE, and interest coverage ratios for the known discharging
firms. In some cases, this group appears slightly stronger financially than the coastal industry
firms as a whole, although certain subsets show weaker performance on some measures, returns
are still above the lowest quartile. The interest coverage ratio is still below 3 for all groups but
the majors, although possibly slightly better than that for the coastal group as a whole. The
group of known dischargers is weak financially, but again, as for the coastal group as a whole,
not among the weakest groups in the industry. Equity and working capital measures also might
be important indicators of impacts in the discharging group due to potential limitations in the
ability of this group to borrow capital.
Several overall conclusions about the Gulf coastal operators can be made. Differences
between known dischargers and all operators are probably not great and are likely to follow no
particular pattern. Based on the arbitrary divisions made between groups in terms of size and
corporate structure, in some cases known dischargers appear possibly a little healthier than
nondischargers. Neither group is particularly financially healthy when compared to the industry
as a whole. In most cases, however, on average, both known dischargers and the group of all
Gulf coastal operators fall within the range between median and lowest quartile, which can be
characterized as weak but not poor financial performance.
Firms Operating in Cook Inlet
The Cook Inlet operators10 generally appear to be about as healthy financially as the
Gulf of Mexico major operators as a group (the Cook Inlet operators also are majors). Median
10Numbers for this concerns about section were taken from annual reports only. Because of
concerns about confidential business information and the small numbers of operators involved,
medians for coastal revenues and operating costs are not presented.
3-38
-------
total assets and equity are somewhat higher (see Table 3-11) among the Cook Inlet operators
than among the Gulf coast majors, and median working capital and the current ratio are also
higher (the current ratio is 1.09 compared to 0.98 among the Gulf coast majors) although
whether these differences are significant has not been determined. Return on assets is not
appreciably different between Gulf and Cook Inlet operators (both groups show about a 2
percent median ROA, which is below the industry median of 3.5 percent, but well above the
lowest quartile of -1.3 percent). Return on equity might be slightly better among the Gulf
majors (7.6 percent as compared to 6.8 percent among the Cook Inlet majors), but both groups
are somewhat above the median 6.2 percent return noted for the industry. The interest coverage
ratio is below 3 (i.e., 2.0), and is slightly lower than the median for the Gulf majors (i.e., 3.0).
3.4 REFERENCES
American Petroleum Institute (API). 1988. [Exploration and Production Industry Associated
Wastes Report. Washington, DC. May.
American Petroleum Institute (API). 1991. Detailed Comments on EPA Supporting Documents
for Well Treatment and Workover/Completion Fluids. Attachment to API comments on
the March 13 proposal. May 13. (Offshore Rulemaking Record, vol. 146.)
American Petroleum Institute (API). 1994. Basic Petroleum Data Book, Petroleum Industry
Statistics. Volume XIV, Number 2. May.
AOGA. 1993- Offshore Discharges in Cook Inlet: What Is Their Effect on the Aquatic
Environment? Technical Fact Sheet. No. 93-1. August.
Acosta, D. 1981. Special Completion Fluids Outperform Drilling Muds. Oil and Gas Journal.
March 2. (Offshore Rulemaking Record, vol. 25.)
Arctic Laboratories Limited et al. 1983. Offshore Oil and Gas Production Waste
Characteristics, Treatment Methods, Biological Effects, and Their Applications to
Canadian Regions. Prepared for Environmental Protection Services. April. (Offshore
Rulemaking Record, vol. 110.)
Baker, R. 1985. A Primer of Offshore Operations. Second edition. Petroleum Extensive
Service, University of Texas at Austin.
Dun & Bradstreet. 1993. Industry Norms, 1992-1993.
3-39
-------
TABLE 3-11
MEDIAN FINANCIAL STATISTICS - ALL FIRMS, COOK INLET
Financial statistic
Total assets
Owner equity
Working capital
Current ratio
Return on assets
Return on equity
Interest coverage ratio
Median value
$17,862,000
$5,028,000
$156,000
1.0876
0.0195
0.0685
2.0203
3-40
-------
Eastern Research Group, Inc. (ERG). 1992. Memorandum from Eric Sigler, ERG, to Ann
Watkins and Joe Ford, U.S. EPA. Status Update on Coastal Database. March 31.
Eastern Research Group, Inc. (ERG). 1993a. Memorandum from Matt Murphy, ERG, to
Allison Wiedeman, U.S. EPA, Well Status Update for Alabama, Florida, and Mississippi.
June 1.
Eastern Research Group, Inc. (ERG). 1993b. Memorandum from Matt Murphy, ERG, to Joe
Ford, U.S. EPA. Changes to Coastal Data Base, August 9.
Eastern Research Group, Inc. (ERG). 1994a. Memorandum from Matt Murphy, ERG, to
Allison Wiedeman, U.S. EPA. Coastal Oil and Gas Activity in the Atlantic Region.
Julyl.
Eastern Research Group, Inc. (ERG). 1994b. Memorandum from Maureen Kaplan, ERG, to
Allison Wiedeman, U.S. EPA. Stand-alone Projects: ERG Multi-well Structures and
Single-well Structures in the 308 Survey Data. February 11.
Gray, G.R., H. Darley, and W. Rogers. 1980. Composition and Properties of Oil Well Drilling
Fluids. January.
Johnston, Daniel. 1992. Oil Company, Financial Analysis in Nontechnical Language.
MarathonAJNOCAL. 1994. Zero Discharge Analysis: Cook Inlet, Alaska. Marathon Oil
Company and UNOCAL Corporation. March.
Meek, R.P., and J.P. Ray. 1980. Induced Sedimentation, Accumulation, and Transport
Resulting from -Exploratory Drilling Discharges of Drilling Fluids and Cuttings on the
Southern California Outer Continental Shelf. Symposium—Research on Environmental
Fate and Effects of Drilling Fluids and Cuttings. Sponsored by API, Lake Buena Vista,
Florida. January.
Oil and Gas Journal (OGJ). 1991. OGJ 300: Smaller List, Bigger Financial Totals. Vol. 89,
No. 39. September 30. pp. 49-56.
Oil and Gas Journal (OGJ). 1992. Financial Operating Results Sag for OGJ 300 Companies.
Vol. 90, No. 39, September 28. p. 49.
Oil and Gas Journal (OGJ). 1994a. Cook Inlet Maintaining Oil Flow in Spite of Budget
Restrictions. June 20. pp. 21-23.
Oil and Gas Journal (OGJ). 1994b. Drewry Shipping Consultants. August 22, pg. 18.
Oil and Gas Journal (OGJ). 1994c. OJG Newsletter. Vol. 92, No. 32, August 8. p. 2.
Oil and Gas Journal (OGJ). 1994d. Total Earnings Rose, Revenues Fell in 1993 for OGJ 300
companies. Sept. 5, pgs. 49-59.
Pennwell. 1994. U.S.A. Oil Industry Directory, 33rd Edition.
3-41
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Radian Corporation. 1977. Industrial Process Profiles for Environmental Use. Chapter 2: Oil
and Gas Production Industry. EPA/600/2-77/023b. February. (Offshore Ruling Record,
vol. 18.)
Ray, J.P. 1979. Offehore Discharges of Drill Cuttings. Outer Continental Shelf Frontier
Technology. Proceedings of a Symposium. National Academy of Sciences. December 6.
(Offehore Rulemaking Record, vol. 18.)
SAIC. 1994a. Oil and Gas Exploration and Production Handling Methods in Coastal Alaska.
SAIC. 1994b. Data Listing from Coastal Oil and Gas Questionnaire. Version 5. May 27.
SAIC. 1994c. Memorandum from Scott Henderson, SAIC, to Chuck White, EPA. Preliminary
estimates from Tables A1-A10 and Tables B1-B11 of the Coastal Oil and Gas
Questionnaire.
SAIC. 1994d. Memorandum from Scott Henderson, SAIC, to Chuck White, EPA. Estimates
from the Coastal Oil and Gas Questionnaire per ERG request. Sept. 13.
SAIC. 1994e. November Memorandum (to be written).
SAIC. 1994f. September 9,1994 Memorandum.
U.S. Bureau of the Census. 1991. County Business Patterns: U.S. Summary.
U.S. Environmental Protection Agency. 1987. Report to Congress: Management of Wastes
from the Exploration, Development, and Production of Crude Oil, Natural Gas, and
Geothermal Energy, vol. 1. EPA/530/SW-88/003. December. (Offehore Rulemaking
Record, vol. 119.).
U.S. Environmental Protection Agency. 1992. Memorandum from Allison Wiedeman, Project
Officer, to Marv Rubin, Branch Chief. Supplementary Information to the 1991
Rulemaking on Treataent/Workover/Completion Fluids. December 10.
U.S. Environmental Protection Agency. 1993. Economic Impact Analysis of Effluent
Limitations Guidelines and Standards for the Offehore Oil and Gas Industry.
U.S. Environmental Protection Agency. 1994a. Memorandum from Allison Wiedeman, EPA to
file. Coastal Oil and Gas Activity in California, Alabama, Mississippi, and Florida.
U.S. Environmental Protection Agency. 1994b. Trip Report to Cook Inlet, Alaska and North
Slope Oil and Gas Facilities. August 25-29,1993. August 31.
U.S. Environmental Protection Agency. 1995. Development Document for Proposed Effluent
Limitations Guidelines and Standards for the Coastal Subcategory of the Oil and Gas
Extraction Point Source Category.
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Walk, Haydel and Associates. Undated. Industrial Process Profiles to Support PMN Review:
Oil Field Chemicals. Prepared for U.S. EPA, Undated; received by EPA June 24,1983.
(Offshore Rulemaking Record, vol. 26.)
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SECTION FOUR
ECONOMIC IMPACT ANALYSIS METHODOLOGY OVERVIEW
AND AGGREGATE COMPLIANCE COST ANALYSIS
4.1 OVERVIEW OF METHODOLOGIES
This analysis discusses the impacts of the proposed and selected regulatory options for
effluent limitations guidelines and standards for the coastal subcategory of the oil and gas
production industry in the affected coastal regions (Le., the Texas/Louisiana portion of the Gulf
of Mexico Region, known here as the Gulf of Mexico region,1 and Cook Inlet, Alaska). The
overall analysis covers:
• Compliance costs to industry.
• Production losses (in terms of quantities of hydrocarbons not produced compared
to a no-regulation [baseline] scenario).
• Lost economic lifetime (i.e., the loss of productive years associated with wells
shutting in earlier under the regulation than under a baseline scenario).
• Numbers of wells immediately ceasing production as a result of the regulation
(first-year shut in).
• Losses of revenues to operators, in terms of annualized losses and net present
value (NPV) of production,2 state governments, and the federal government.
• Firm-level impacts (firm failure analysis).
• Employment impacts (losses and gains in employment).
• Balance of trade and inflation impacts.
• Regulatory flexibility (an analysis of whether impacts are disproportionate on
small businesses).
*A11 discussions of the Gulf of Mexico address Texas and Louisiana operations only.
2NPV is the total stream of production revenues minus costs over a period of years (the
well's or platform's lifetime) discounted back to present value.
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• Impacts on new sources (which looks at impacts on NPV and the internal rate of
return [another measure of profitability]).
These individual analyses are interrelated, with the output of one analysis often used as
input for another analysis. The general flow of the analyses and their relationship to one another
are shown in Figure 4-1. As the figure shows, the first step in the analysis is to identify the
appropriate inputs. Because compliance costs (capital as well as operating and maintenance
[O&M] costs) are one of the major inputs to all of these analyses, how these costs are annualized
is a key methodological decision. Section 4.2 discusses how and why costs are annualized,
Section 43 describes all the regulatory options under consideration and the options selected for
these effluent guidelines, and Section 4.4 presents total aggregate compliance costs associated
with each of the BAT regulatory options and the effluent guidelines as a whole (the costs for the
selected regulatory options).
The first major analysis following cost annualization is the production loss analysis.3 In
general, this analysis uses well-specific compliance costs calculated based on volumes of wastes
generated by each discharging well or platform surveyed in the Section 308 survey.4 The well-
specific cost is determined using a cost per barrel derived from the compliance costs (capital and
O&M) estimated for each treatment facility (for Gulf region produced water) or derived from
the compliance costs associated with each operator (Cook Inlet produced water drilling wastes).
This analysis uses an economic model of surveyed wells (Gulf of Mexico) and platforms (Cook
Inlet, Alaska) to look at annual cash flow and production decisions (produce/shut in) based
3The cost annualization used in this section (Section Four), Section Five for the Gulf model
only, and Section Six is a simple method using only the discount rate and number of years
assumed to be the average life of wells or platforms or over which drilling occurs. The
production loss model for Cook Inlet uses a much more sophisticated method to annualize costs
that takes into account accelerated depreciation and the modeled life of each platform (see
Section 5.1). The simple annualization used in Section Four, in Section Five for defining impacts
in the Gulf, and in Section Six produces pretax estimates of compliance costs and thus overstates
costs and impacts to producers. The more sophisticated Cook Inlet model calculates the actual
cost in each year faced by producers (a posttax cost).
4Compliance costs in terms of capital and O&M costs to achieve different levels of control
were derived separately from this economic analysis effort and are presented in a separate
document (see U.S. EPA, 1995, for more details on the derivation of compliance costs).
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Input
Facility-Specific
Volume
Facility-Specific
Capital Costs
Input
v^^^i^^^^
~i?.
Facility-Specific
Operating &
Maintenance Costs
Input
1
Output
Employment
Gain
Per-Barrel
Compliance Cost
Loss of Net Present Value
of Production
Production Volume Loss
Production Loss
Model
Federal Tax Revenue Loss
Severance Tax Loss
Baseline versus
Postcompliance
Comparison
Loss of Economic Life
First Year Shut-in
Baseline Shut-in
Firm-Level
Analysis
Employment
Losses
Other, Lesser
Impacts
Postcompliance
Firm Failures
Baseline Firm
Failures
Figure 4-1. Overview of methodology for the economic impact analysis.
4-3
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primarily on cash flow (see Section Five for more details). Compliance costs and production
losses lead to losses in economic lifetimes (the decision to shut in is made earlier than if the
regulation were not in effect), which leads to production losses. Sometimes the decision process
indicates that the operator would shut in a well or platform as soon as the regulation becomes
effective (a first-year shut-in); this result is also noted. Compliance costs and production losses
also lead to declines in the present value of net income (i.e., NPV), which can be estimated when
the model outputs from a baseline scenario are compared to those from a postcompliance
scenario. The detailed methodology for the production loss modeling is discussed in Section Five
and Appendix A. Results are presented in Section Five.
Production losses, first-year well shut-ins, and declines in the present value of net income
(NPV) lead to secondary impacts on federal and state revenues (see Section Five), operator
revenues (see Section Five), employment (see Section Seven), and possibly the balance of trade
and inflation (see Section Eight). The nature of the Section 308 survey is such that well impacts
cannot be linked to individual operators (operators were censused but wells were surveyed, and
wells were not selected on an operator-by-operator basis); thus, firm-level impacts are
investigated separately from well- or platform-based impacts. On a case-by-case basis, however,
where such information is available, specific model results are added to the firm failure analysis
results.
Annual compliance costs are again used for the firm-level analysis, compiled on an
operator-by-operator basis. These costs are compared to working capital and equity among the
affected firms. Where a reduction in working capital or equity exceeds 5 percent, a more in-
depth analysis is undertaken, looking at well-specific data, where possible, to identify whether
firm failure is a possibility (see Section Six).
4.2 COST ANNUAIJZATION PURPOSE AND METHOD
Cost annualization is used to estimate the annual compliance cost to the operators of new
pollution control equipment. The cost of additional pollution control equipment can be divided
between two components: the initial capital investment to purchase and install the equipment,
4-4
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and the annual cost of operating and maintaining such equipment. Capital costs are a one-time
expense incurred only at the beginning of the equipment's life, and O&M costs are incurred
every year of the equipment's operation.
To determine the economic feasibility of upgrading a treatment facility or transporting
and disposing wastes at a commercial facility, the costs must be compared against the well's
annual revenues and its operator's capital structure. The initial capital outlay should not be
compared against the well's or operator's income in the first year because this capital cost is
incurred only once. Additionally, armualizing costs over several years reflects the common
practice of financing capital expenditures. Tins initial investment, therefore, should be spread
out over either the well's or platform's life or the equipment's life. Annualizing costs is a
technique that allocates the capital investment over the lifetime of the equipment, incorporates a
cost-of-capital factor to address the costs associated with raising or borrowing money for the
investment, and includes annual O&M costs. The resulting annualized cost represents the
average annual payment that a given company will need to make to upgrade its facility. The
annualized cost is analogous to a mortgage payment, which spreads the one-tune investment in a
home into a series of constant monthly payments. As noted above, cost annualization in this
section (and for the Gulf model in Section Five and hi Section Six) is a simplified version of the
cost annualization performed in the Cook Inlet model.
In this section, costs are annualized using two inputs: discount rate and time period over
which payments are made. The discount rate was calculated using the Section 308 survey
responses to a question asking respondents for their cost of capital. The average cost of capital
over all coastal respondents was reported as 8 percent, and this is used as the discount rate. The
time period over which costs are annualized varies, depending on the waste stream under
consideration and the location of the affected wells or platforms. In Cook Inlet, remaining
platform lives average 11 years in the baseline, although under some options these lives could be
slightly less; thus, a 10-year remaining project life was assumed in this section for produced water
options. Drilling will most likely only take place over a 7-year period (UNOCAL/Marathon,
4-5
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1994).5 Because the drilling waste disposal equipment might not be used past this 7-year life, a
7-year period has been used to amortize the capital costs of drilling-waste disposal options.6 In
the Gulf of Mexico, currently productive wells are expected to have an average economic life of
about 15 years, but under postcompliance options this average life drops to as little as 10 years
(see Section Five for the analysis that estimates this economic life). Because well life does not
necessarily relate to treatment facility life (wells can be shut in and new wells can be drilled to
replace them), the 10-year period over which to amortize costs also was considered a
conservative estimate of project lifetime. The shorter the time frame used in the analysis, the
more conservatively high will be the estimate of annual compliance costs.
The cost annualization for drilling wastes in this section was performed in a slightly
different manner than for the other waste streams. Unlike the other wastes, which could be
considered to be disposed every year, drilling wastes are disposed of sporadically with each well
drilled. Based on a drilling schedule provided by Cook Inlet operators, the above discount rate
and time period assumptions, and capital and O&M costs provided by SAIC, which determined
costs for all drilling projects planned through 2002 (EPA, 1995), a present value for all costs over
the 7-year period was calculated and then annualized to create a consistent stream of payments
over the timeframe. This approach is discussed in more detail in Section 4.32.
4.3 THE REGULATORY OPTIONS
The engineering cost estimates that feed into the cost annualization model are based on a
set of regulatory options developed by EPA. This section summarizes these options. The
5Industry supplied EPA with its plans to drill in Cook Met until 2002—approximately 7 years
after the expected promulgation date of this rule. Beyond that date, drilling plans could not be
provided. Thus drilling costs are annualized over 7 years, rather than a longer time period to
provide a conservatively high estimate of annual compliance costs.
''This is a conservative assumption that overstates compliance costs as reported in this section.
In Section Five, the Cook Inlet model is able to determine the actual life of the platforms in
question to compute a more precise, posttax compliance cost estimated to affect producers.
4-6
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derivation of the initial engineering cost estimates under each option is discussed in the
Development Document (U.S. EPA, 1995).
EPA is required under Sections 301,304, 306, and 307 of the Clean Water Act (the Act)
to establish effluent limitations guidelines and standards of performance for industrial
dischargers. To further these requirements, EPA has proposed the following effluent guidelines
and standards:
• BPT—-For produced sand only.
• BCT—Effluent reductions employing the best conventional pollutant control
technology as required under Section 304(b)(4).
• BAT—Effluent reductions employing the best available control technology
economically achievable as required under Section 304(b)(2).
• NSPS—New source performance standards covering direct discharging new
sources as required under Section 306(b) of the Act.
• PSES—Pretreatment standards for existing sources.
• PSNS—Pretreatment standards for new sources.
Best practicable technology (BPT) regulations were promulgated in 1979.
For the purposes of analysis, the range of BCT, PSES, NSPS, and PSNS options
evaluated by EPA are identical to BAT options although the pollutants controlled through BCT
requirements are total suspended solids (TSS) and oil and grease only (conventional pollutants).7
No existing indirect dischargers are known and no new indirect dischargers are anticipated; thus,
PSES and PSNS options for indirect dischargers are not associated with any costs or impacts.
(In all cases selected PSES and PSNS options equal NSPS options.) This section discusses the
BAT, NSPS, and BCT options for the following waste streams:
• Produced water
'Preferred BCT options, however, in some instances differ from preferred BAT options.
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• Drilling fluids and cuttings
• Well treatment, workover, and completion wastes (TWC)
The following waste streams also are regulated:
»
« Deck drainage from platforms
• Produced sand
• Sanitary waste
• Domestic waste
This ETA does not assess impacts associated with these four wastestreams because EPA is
proposing regulatory options for them that are equal to current practice and therefore impose no
costs to the industry. Note also that this EIA does not assess impacts outside the Gulf of Mexico
(Texas and Louisiana only) and Cook Inlet regions, since no coastal oil and gas operations
outside these two regions currently discharge wastes nor are they expected to in the future (see
Section Three).
The BAT, NSPS, and BCT options for produced water, drilling waste, and TWC are
described below in detail. (BAT options considered for each of these types of waste are
summarized in Table 4-1.) Preferred options for produced sand, deck drainage, sanitary waste,
and domestic wastes also are briefly discussed.
4.3.1 Produced Water
Some operations in both the Gulf of Mexico and Cook Inlet currently discharge produced
water (this analysis does not take into account the requirements of EPA Region 6 General
Permits for the Coastal Oil and Gas Industry covering disposal of produced water). The five
BAT options proposed for produced water are as follows:
• Option #1 is identical to BPT (a no-cost alternative).
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TABLE 4-1
BAT REGULATORY OPTIONS CONSIDERED IN THE ECONOMIC IMPACT ANALYSIS
Type of
Waste Stream
Produced
water
Drilling
wastes
TWC
Name
Option #1
Option #2
Option #3
Option #4
Option #5
Option #1
Option #2
Option #3
Option #1
Option #2
Description
BPT — current regulatory requirement
Offshore limitations
Zero discharge/BPT Cook Inlet
Zero discharge/offshore limitations Cook Inlet
Zero discharge
Zero discharge/offshore limitations Cook Inlet
Zero discharge/offshore limitations plus 1-million-ppm
toxicity limit Cook Inlet
Zero discharge
BPT
Zero discharge/offshore limitations Cook Inlet
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• Option #2 requires all operations, including those in the Gulf of Mexico and
Cook Inlet, to meet the same limitations as those required of offshore operations
(these limitations can be met using improved gas flotation technology).
• Option #3 requires zero discharge, except that Cook Inlet operations are allowed
to continue with BPT practices.
• Option #4 requires zero discharge, except that Cook Inlet operations are required
to meet offshore limitations (which can be achieved using improved gas flotation
technology).
• Option #5 requires all operations, including those in the Gulf of Mexico and
Cook Inlet, to meet zero-discharge requirements (which can be met either
through the use of injection wells or through transportation of wastes to
commercial disposal facilities).
The preferred BAT regulatory option is Option #4, which prohibits discharge in the Gulf
of Mexico but allows operations in Cook Inlet to meet offshore limitations. The selected NSPS
option is Option #5 (zero discharge, all regions) (see Section Ten for a discussion of NSPS
analyses). All options fail the BCT cost test (see EPA, 1995, for more details on BCT cost
tests), so BCT is set equal to BPT.
4.3.2 Drilling Fluids and Cuttings
All coastal areas are currently achieving zero discharge of drilling fluids and cuttings with
the exception of Cook Inlet. EPA Region 6 has promulgated a General Permit prohibiting the
discharge of drilling fluids and cuttings (58 FR 49126, September 21,1993); discharge of these
wastes also is prohibited in states outside Region 6 with coastal oil and gas operations (see
Section Three), except for Alaska. Also included in this waste stream is drill water effluent, but
little to no drill water effluent is currently discharged (EPA, 1995). Three BAT options are
proposed:
• Option #1 requires zero discharge, except that Cook Inlet operations are required
to meet offshore limitations (30,000 ppm toxicity limitation). This option reflects
current practice and is a no-cost alternative.
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• Option #2 requires zero discharge, except that Cook Inlet operations are required
to meet offshore limitations with a 100,000- to 1-mfflion-ppm toxicity limitation in
the suspended paniculate phase (SPP).
• Option #3 requires zero discharge, regardless of location.
EPA is co-proposing all three options. The selected NSPS option is NSPS=BAT (i.e.,
whichever BAT option is selected for promulgation, NSPS will be set to equal that option).
Since neither Option #2 nor Option #3 passes the BCT cost test, BCT is set equal to BPT.
Note that because drilling wastes are only being discharged in Cook Inlet, operations in this
region alone will incur BAT costs. Additionally, because no new platforms subject to NSPS
requirements are expected to be constructed in Cook Inlet, no NSPS costs are anticipated.
4.33 TWC Wastes
Two BAT options are considered for TWC:
• Option #1 requires BPT (except in Region 6 freshwaters, where zero discharge
would be required, which is current practice).
• Option #2 requires TWC limitations to equal the selected produced water option
(in this case zero discharge, except for improved gas flotation in Cook Inlet).8
Options #1 and #2 are co-proposed. The selected NSPS option is NSPS=BAT (i.e.,
depending on whichever BAT option is selected for promulgation). Since Option #2 fails the
BCT cost test, BCT is set equal to BPT.
is a no-cost option for Cook Inlet, since TWC is commingled with produced water and
costs calculated for produced water disposal include the cost of disposing of the commingled
waste.
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4.3.4 Other Miscellaneous Wastes
For produced sand, zero discharge is proposed for BPT, BAT, and NSPS. BCT is set
equal to BPT. This is a no-cost option (zero discharge is current practice).
For deck drainage, BAT and NSPS requirements are proposed to be the same as BPT:
no free oiL No costs or impacts are expected because the proposed requirements are current
practice. BCT is set equal to BPT (the other option fails the BCT cost test).
The proposed NSPS and BCT options for sanitary waste are set equal to BPT (and no
discharge of foam for NSPS). No BAT limitations are considered because the only parameters
considered for regulation are conventionals. No costs or impacts are expected because the
proposed requirements are current practice.
The proposed options for domestic wastes are NSPS equal to BPT (and no discharge of
foam for NSPS), BCT equal to BPT, and no discharge of foam for BAT. No costs or impacts
are expected because the proposed requirements are current practice.
4.4 AGGREGATE COMPLIANCE COSTS
This section calculates the aggregate compliance costs for BAT options for the waste
streams considered in this EIA and also estimates costs of NSPS in the selected option for
produced water and for Option #2 for TWC (NSPS costs for other waste streams are zero).
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4.4.1 BAT Options
4.4.1.1 Produced Water
The aggregate compliance costs for produced water are derived from estimates of capital
and operating costs for the following types of locations and pollution control approaches (see
U.S. EPA, 1995):
Gulf of Mexico
Improved gas flotation: Capital and operating expenditures to install
improved gas flotation equipment (i.e., equipment capable of meeting the
more stringent offehore limitations on grease and oil) at discharging
separation/treatment facilities were estimated. The discharging
separation/treatment facilities of concern are those that will still have
discharge permits in 1996. The most recent permit data from the
Louisiana Department of Environmental Quality and the Texas Railroad
Commission were used to identify current dischargers. The regulatory
baseline, however, requires that only those operations discharging after
third quarter 1996 be considered. Therefore, treatment facilities were
identified as likely to be operating after the third quarter 1996 using
reviews of permit compliance schedules in the Louisiana permit database,
reviews of court-ordered compliance schedules for Texas dischargers, and
information obtained from the Section 308 survey concerning whether the
facility would be operating in 1996. Only the treatment facilities
continuing to discharge in 1996 were assigned costs.
Zero discharge: Capital and operating expenditures to install injection
wells or to transport produced water to commercial disposal facilities were
estimated for the same group of treatment facilities identified above. In
general, injection wells were assumed to be installed at the larger
treatment facilities, whereas produced water from the smaller facilities was
assumed to be transported to a commercial disposal facility.
Cook Inlet
Improved gas flotation: Costs to install and operate improved gas
flotation equipment were derived for each platform (where platform
treatment and discharge currently takes place) or centralized onshore
treatment facility (where produced water is piped to shore for treatment).
Zero discharge: Costs to install and operate injection wells, as well as
relevant piping, were derived for each platform or onshore treatment
facility.
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TABLE 4-2
AGGREGATE ANNUAL COSTS FOR BAT OPTIONS BY
REGULATORY OPTIONS ($1992)
Type of Waste Stream
Produced water
Drilling wastes
TWC
. Option
Number
Option #1
Option #2
Option #3
Option #4
Option #5
Option #1
Option #2
Option #3
Option #1
Option #2
Aggregate
Annual Cost
(Pretax)
$0
$12,371,872
$28,615,098
$30,862,336
$50,693,181
$0
$1,370,685
$3,889,386
$0
$605,645
Source: ERG estimates based on SAIC engineering costs from U.S. EPA (1995).
4-14
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Once the capital costs were annualized and added to operating costs, costs for each of
these options within regions were combined, yielding the costs of the regulatory options (Le.,
Option #2, improved gas flotation, used the sum of costs for improved gas flotation among all
facilities in the Gulf of Mexico with the costs of gas improved flotation derived for the platforms
and onshore treatment facilities in Cook Inlet).
Aggregate compliance costs for Options #1 through #5 are shown in Table 4-2. The
compliance costs (other than for Option #1) range from $12.4 million to $50.7 million. The
selected option, Option #4, is associated with costs totaling $30.9 million. Note that all
compliance costs have been calculated pretax. This approach overestimates the annual costs to
industry, because the state and federal governments will partially subsidize these expenditures
through deductions for accelerated capital equipment depreciation and increased operating costs,
which serve to reduce taxable income. Although posttax compliance costs to industry are not
calculated, the reduction in tax revenues to the state and federal governments from both
compliance cost effects and production losses is estimated in Section Five.
4.4J..2 DrMng Waste
Aggregate compliance costs for drilling wastes (Cook Inlet only) are derived from
estimates of capital and operating costs for the following types of pollution control approaches
(see U.S. EPA, 1995):
• 1-million-ppm toxicity limit: Operations likely to use landfills or dedicated
disposal wells were identified based on discussions with the operators in Cook
Inlet (U.S. EPA, 1995). Costs per barrel of waste disposed were calculated for
landfill disposal. Capital costs of installing injection wells and injection equipment
and modifying platforms were developed. Operating costs for injection wells were
also derived. All operating costs were converted to a cost per new or recompleted
well drilled based on volume expected to require disposal (17 percent of all
drilling waste generated—see U.S. EPA, 1995). A drilling schedule was then
developed based on discussions with operators (Table 4-3). A cost schedule was
developed based on the drilling schedule (Table 4-4). In the first year, all capital
costs for any operators incurring a capital cost are included plus the costs to
dispose of wastes from the number of wells planned to be drilled in the first year.
The second and subsequent years only include costs for disposing the wastes from
4-15
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wells planned. The net present value of these expenditures was calculated and
then annualized over the 7-year period to produce a consistent stream of
expenditures over the 7-year period (Table5 4-4).
• Zero-discharge limit: The same procedure was followed as that presented above
with one major exception. Instead of assuming that 17 percent of drilling waste
would need to be disposed of, all waste was assumed to require disposal. Costs
increase for two reasons. First, since total volumes disposed per well increase,
costs per well drilled increase. Second, the increase in total volumes requires the
installation of one additional injection well for one operator; thus, capital costs
also increase (Table 4-5).
The aggregate compliance costs for Options #1 through #3 are shown in Table 4-2.
Compliance costs range from $0 to $3.9 million.
4.4.1.3 TWC
EPA is co-proposing Options #1 and #2 for TWC. Option #1 is equivalent to BPT;
Option #2 requires zero discharge in the Gulf and offshore limitations for Cook Inlet. Because
TWC fluids can be commingled with produced water, EPA has selected these same requirements
as the preferred produced water option as Option #2 for TWC. All costs for TWC in Cook
Inlet are inherently part of the costs to meet produced water options in Cook Inlet because TWC
is currently commingled there. Thus, no additional costs are incurred for this TWC option in
Cook Inlet. But for the Gulf, incremental costs for disposing of TWC would be incurred under
Option #2. The costs for TWC disposal under Option #2 in the Gulf are O&M costs only.
Costs for disposing of TWC under Option #2 are generated similarly to that for Gulf of
Mexico produced water (i.e., facflity-by-facility with zero discharge achieved assuming commercial
disposal or injection, depending on the size of the permitted treatment facility). Costs for each
option are shown in Table 4-2. Compliance costs are approximately $0 or $0.6 million per year.
4-19
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TABLE 4-6
AGGREGATE ANNUAL COSTS FOR SELECTED BAT REGULATORY OPTIONS
($1992)
Type of Waste Stream
Produced water
Drilling waste
TWC
Total
Selected
Option
Number
Option #4
Options #1, #2,
or #3
Options #1 or
#2
Aggregate Annual
Cost' Range
(Pretax)
$30,862336
$0 to $3,889^86
$0 to $605,645
$30,862,336 to
$35,357,367
Source: ERG estimates based on SAIC engineering costs from U.S. EPA (1995).
4-20
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4.4.1.4 Total Aggregate Compliance Costs for the Selected BAT Regulatory Options
Table 4-6 presents the total aggregate compliance costs for the selected regulatory
options. These regulatory requirements will amount to $30.9 to $35.4 million annually,
depending on which drilling waste and TWC options are selected.
4.4.2 NSPS Cost Estimate for Produced Water
EPA estimates that six new projects will be constructed in the Gulf of Mexico each year
over the next 15 years (U.S. EPA, 1995). Total capital costs for a zero-discharge option were
estimated to be $2,038,738 and O&M costs were estimated to be $370,549.
Capital costs for six projects are assumed to be incurred in every year, and every year
there is an additional O&M cost for each new project. Thus, in year 1 capital costs for six
projects and O&M costs for six projects are incurred. In year 2, capital costs for six projects and
O&M costs for 12 projects are incurred. In year 3, capital costs for six projects and O&M costs
for 18 projects are incurred, and so on out to 15 years. The present value of these capital and
O&M outlays over 15 years9 is then computed (at an 8 percent real discount rate). Note that it
is assumed that the initial outlay occurs at the end of 1996 and recurs at the end of every period
thereafter (as opposed to occurring at the beginning of the period, which provides a slightly
different result). The present value is then annualized. The total present value of the zero-
discharge option is $38.4 million with an annual cost of $4,482,309 (Table 4-7).
4.43 NSPS Cost Estimate for TWC
EPA estimates that 45 new wells meeting the definition of a new source will be drilled
each year and will require annual disposal of TWC fluids (U.S. EPA, 1995). The costs per year
9A 15-year lifetime is assumed rather than 10 years because new wells or projects should have
a longer productive life than existing wells or projects.
4-21
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TABLE 4-7
TOTAL ANNUAL COSTS FOR ALL SELECTED REGULATORY OPTIONS
($1992)
Type of Waste Stream
Produced water
Drilling waste
TWC
NSPS, produced water
NSPS, TWC
Total
Selected
Option
Number
Option #4
Option #1, #2,
or #3
Options #1 or
#2
Option #4
Options #1 or
#2
Aggregate Annual
Cost Range
(Pretax)
$30,862,336
$0 to $3,889,386
$0 to $605,645
$4,482,309
$0 to $519,848
$35?344,645 to
$40,359,524
Source: ERG estimates based on SAIC engineering costs from U.S. EPA (1995).
4-22
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for each group of 45 wells will total $78,831 for the preferred no discharge option. As above,
each year another group of 45 wells are assumed to begin production, so in the first year, $78,831
will be incurred, in the second year, $157,662, and so on out to 15 years. The present value of
these O&M outlays over 15 years is then calculated and annualized as for produced water,
above. The total annual cost of NSPS for TWC is computed to be $4,449,627 in present value or
$519,848 annually. Depending on which NSPS option is chosen (based on choice of BAT
option), costs will thus be $0 to $0.5 million per year.
4.4.4 Total Estimated Cost of the Effluent Guidelines
The estimated cost of the effluent guidelines is $30.9 to $35.4 million per year for BAT
requirements and $4.5 to $5.0 million per year for NSPS requirements, for a total of $35.3 to
$40.4 million per year. Thus, this rulemaking does not qualify as a major rule under Office of
Management and Budget (OMB) guidelines (Executive Order 12866) and a Regulatory Impact
Analysis (RIA) is not required. Note that the total maximum cost of the rule ($40.4 million) is a
very small percentage of coastal revenues and operating costs (the direct costs of operating the
business, i.e., not including general and administrative costs, depletion, depreciation, taxes,
interest, etc.). Total revenues among coastal firms (Texas, Louisiana, and Cook Inlet, Alaska,
only) are estimated to be $6.1 billion per year. Thus, the total annual cost of the Coastal
Guidelines is estimated to be 0.7 percent of annual coastal revenues. The total annual coastal
operating costs among coastal firms is estimated to be $1.2 billion; thus, annual compliance costs
are 3.3 percent of total annual operating costs.
4.5 REFERENCES
ARCO. 1994. Telephone contact between Allison Wiedeman, EPA, and Jim Short, ARCO,
Alaska. May 9.
Marathon/UNOCAL. 1994. Zero Discharge Analysis: Cook Inlet, Alaska. Marathon Oil
Company and UNOCAL Corporation. March.
4-23
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U.S. EPA. 1993. Economic Impact and Regulatory Flexibility Analysis of Proposed Effluent
Guidelines and NESHAP for the Pulp, Paper, and Paperboard Industry. EPA-821-R-93-
021. Office of Water. November.
U.S. Environmental Protection Agency. 1995. Development Document for Proposed Effluent
Limitations Guidelines and Standards for the Coastal Subcategory of the Oil and Gas
Extraction Point Source Category. EPA, JanuarySl.
4-24
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SECTION FIVE
PRODUCTION LOSS IMPACTS AND OTHER IMPACTS TO
WELLS AND FACILITIES
This section describes the production loss model developed to simulate the economic
performance of coastal production and drilling projects. Note that firm-level impacts are
discussed in Section Six. Analysis of Cook Inlet, Alaska, projects incorporates current
production, future drilling, and future production, while Gulf of Mexico projects are analyzed in
current production scenarios only because of a lack of information on planned drilling in the
Gulf.1 Section 5.1 presents a description of the economic simulation methodology for Cook
Inlet, and Section 5.2 describes the Gulf of Mexico model. The results of production loss
modeling for both Cook Inlet and the Gulf of Mexico are presented in Section 53. Although
the Cook Inlet and Gulf of Mexico models have similar bases, a number of differences
distinguish the models sufficiently to warrant separate presentations. In all analyses, a baseline is
defined, in which the modeled wells and platforms are assumed to be operating without
incremental compliance costs. This baseline scenario is compared to a postcompliance scenario
to estimate the incremental impacts of the rulemaking.
Appendix A of this EIA presents a selection of detailed derivations of assumptions used
in these models. Appendix B provides greater detail for the Cook Inlet production loss model
and presents the calculations summarized in the report text. Appendix C presents details of the
Gulf of Mexico production loss model.
1The impact to new BAT wells (i.e., development wells added to existing treatment facilities
without extensive site preparation work) in the Gulf coastal region should be minimal since these
wells will typically face the marginal cost rather than the average cost of disposal (the cost to add
an additional volume of produced water to a treatment facility, given sufficient capacity, is much
less than the average cost per existing well to convert to zero discharge. Furthermore, these
costs should be substantially offset by a new development well's rate of hydrocarbon production,
which tends to be much greater per volume of produced water than older wells. It is unlikely
that plans to drill BAT wells will be curtailed because of effluent guidelines requirements, given
the large number of coastal wells currently injecting produced water. Barriers to entry for NSPS
wells are addressed separately in Section Ten.
5-1
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5.1 DESCRIPTION OF THE ECONOMIC MODEL FOR COOK INLET, ALASKA
To estimate the effects of the regulatory approaches being considered, the economic
performance of projects is simulated before and after complying with new pollution control
requirements, as discussed above. The following discussion uses the terms "baseline" and
"postcompliance" scenarios to describe the two phases of analysis. This section reviews the
economic model and its components for Cook Inlet, Alaska, production platforms.
Fifteen platforms are located in Cook Inlet and all are in the coastal subcategory of the
oil and gas extraction point source subcategory. Thirteen of these platforms are currently
productive, although fourteen are included in the Cook Inlet model analysis (drilling is planned
at Spark, which is currently shut in). Phillips operates one platform (Tyonek A), Shell Western
operates two that send production to the East Forelands facility (SWEPIA and SWEPIC), and
Marathon/UNOCAL operates four platforms (Anna, Baker, Bruce, and Dillon) and two facilities
(Granite Point, with platforms Granite Point and Spark; and Trading Bay, with platforms Dolly
Varden, Grayling, King Salmon, Monopod, and Steelhead). Marathon/UNOCAL has suspended
production at another platform (Spurr), and since no drilling is planned, it is not included in the
analysis. ARCO's Sunfish project is uncertain, and it is unlikely that a platform will be
constructed (Personal communication between Allison Wiedeman, EPA, and Jim Short, ARCO,
May 9,1994).2 Refer to Figure 3-2 in Section Three for a detailed map of the platforms in
Cook Inlet
5.1.1 Economic Model Overview
The production loss model simulates the performance and measures the profitability of a
petroleum production project. For the Cook Inlet region of the coastal subcategory, a project is
defined as a single platform or island. All projects used in the Cook Inlet model currently exist
and are modeled starting in productive midlife (i.e., not including costs of exploration and
Regulatory costs associated with this project are included in cost estimates, but impacts are
not analyzed.
5-2
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development). For each project, modeling inputs include production and operations cost data,
typical production rates, oil and gas selling prices, continuing drilling schedules and costs, and
other pertinent data. Platform-specific drilling on existing structures and associated increases in
production also are considered. For each project, the model calculates the annual posttax cash
flow for each year of operation as well as cumulative performance measures, such as net present
value (NPV)3 and total lifetime petroleum production.
The schematic design of the model is summarized in Figure 5-1. Three sets of exogenous
values are entered into the model: general model variables (Table 5-1), project-specific variables
(Table 5-2), and pollution control costs (discussed in Section Four).
The model provides calculation procedures and algorithms that duplicate (1) the oil
industry's standard accounting procedures, (2) federal taxation rules enacted by the Tax Reform
Act of 1986, and (3) standard financial rate-of-return calculation methods. The outputs of the
economic model are a series of yearly project cash flows and cumulative performance measures.
The regulatory approaches are incorporated into the economic model by adding relevant
capital costs and operating expenses to the set of cost data. The model calculates all yearly and
cumulative outputs for both the baseline case and regulated cases for each project. When the
results of these two scenarios are compared (external to the model itself), the incremental effects
of regulation can be discerned.
5.1.2 Model Parameters
A distinct set of parameter values is required for each of the platforms modeled; each set
constitutes a complete economic description of the project. The following categories of
parameters are incorporated into the model for each, project:
3NPV is the present value of a stream of net income from baseline year to the end of the
well's economic life (defined to end when operating costs, including pollution control costs,
exceed revenues), discounted annually by the real discount rate.
5-3
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Oil & Gas Prices
Production Levels
Decline Rates
Royalties
Severance Taxes
Corporate Taxes
O&M Costs
Depreciation Schedule
Depletion Allowance
Pollution Control Costs:
Capital Costs
O&M Costs
Incremental Annual
Costs
Yes
Operate for
Another Year
Annual Decision
Is Cash Flow Positive?
No
Calculate:
Net Present Value
Annualized Costs
Summary Statistics
(includes well/platform lifetime and lifetime production)
Closure Analysis
Comparison of Pre- and Postregulatory Model Results
(external to model):
• Well/platform has shortened economic lifetime
or
• Well/platform closes in first year due to annual costs
exceeding revenues in first year
or
• Well/platform determined to close in first year because
investment in pollution control is not economic:
- Unregulated NPV >0
- Regulated NPV<0
Count as Closure:
• Closes in first year
or
• NPV changes from
positive to negative
Figure 5-1. Overview of closure analysis methodology.
5-4
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• Drilling cost per well. Costs for both new production wells and recompletions.
• Drilling schedule. Schedule from 1996 to 2002, detailing platform-specific drilling
activity for new production wells and recompletions (see Table 4-3 in Section
Four).
• Production rates per platform. Initial production rates of oil and gas and
production decline rates.
• Operation and maintenance costs per platform (estimated as a per BOE cost).
• Incremental pollution control costs (estimated as a per BOE cost for the post-
compliance scenario only).
• Tax rates. Rates for federal and state income taxes, severance taxes, royalty
payments, depreciation, and depletion.
• Price. Wellhead selling price of oil and gas (also called the "first purchase price"
of the product).
The parameter values used in the analysis are summarized in Table 5-1 and described more fully
in Appendix A.
5.1.3 Model Calculation Procedures
The model's calculation procedures are a set of rules and logic used to convert the
project parameters into measures of a project's financial performance. These procedures fall into
several categories.
5.13.1 Production Logic
The model equations use exogenous values for peak production rates and production
decline rates to define a production profile for each platform. The model includes current
production as well as production increases attributable to new wells and recompleted wells
brought online. Summary measures of production for the entire project lifetime are also
calculated.
5-7
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Cost Logic
The model equations use exogenous cost data to define the yearly capital and operating
costs of each project. Exogenous parameters include drilling capital costs as well as production
(including existing pollution control costs) and drilling operating costs. Using the model
sequencing logic, the exogenous cost information is converted to annual capital and operating
cost streams. Summary measures of all capital and operating costs are calculated for the entire
project lifetime.
Incremental Pollution Control Cost Logic
A set of equations incorporates the capital and operating costs of additional pollution
control approaches into the project cost stream, thus, creating a simulation of the economic
effect of alternative regulatory approaches. These pollution control costs can include capital and
operating costs for disposal of produced water and drilling wastes. For regulated cases, the
model incorporates both capital and operational pollution control costs. Pollution control capital
costs are incurred in the base year (1996) and a portion is expensed (with the remainder
capitalized). Capital costs for new wells are incurred in the year they are drilled and a portion is
expensed as well.4 Pollution control operating costs are analyzed in the same way as other
operating costs for the project.
5.13.4 Cost Accounting Practices
Specialized oil industry accounting procedures are applied to project cost streams.
Capital and operating costs are analyzed in accordance with oil industry accounting practices.
The model calculates the expensed and capitalized portions of each capital expenditure, which in
turn are used as a base to estimate depreciation for each year of the project's lifetime.
4Note that pollution control costs for Gulf wells are handled differently (see Section 5.2).
5-8
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Price and Revenue Calculations
The wellhead prices of oil and gas are exogenous parameters in the model. The prices
are multiplied by the annual production volumes to calculate annual project revenues. Revenues
are calculated both as an annual stream and as a present-value-equivalent total for the project's
lifetime. The wellhead prices are presented along with other data in Table 5-1.
5.13.6 Earnings and Cash Flow Analysis
The model calculates a project's annual earnings (i.e., the difference between a project's
revenues and its costs). Severance tax and royalty payments are subtracted from earnings before
corporate taxes are removed to calculate annual cash flow. Depreciation and depletion are
treated in these calculations according to federal laws (see Appendix A). Severance taxes on oil
and gas production in Cook Inlet are calculated using an Economic Limit Factor (ELF),
described in Appendix A. Tax rates and royalty rates are presented in Table 5-1.
5.13.7 Financial Performance Calculations
A variety of summary financial measures are calculated in the model. Annual project
cash flows are discounted to the present using an 8 percent discount rate to calculate the NPV of
the project. The 8 percent discount rate is the rate used in the offshore EIA (EPA, 1993a) and
the average reported by all Section 308 survey respondents (EPA, 1993b). In addition, lifetime
petroleum production (on a total and present value basis), total revenues, total costs, and years
of production are summarized. The present value of all project costs is divided by the present
value of all petroleum production to calculate the average cost per unit of production.
The specifics of each of these calculations are given in more detail in Appendix B, which
describes the Cook Inlet production loss model.
5-9
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5.1.4 Interpretation of Model Results
Based on the economic model logic described above, a number of summary statistics and
performance measures are calculated for each project, including:
• NPV of the project.
» Total lifetime production.
• Present value equivalent of production.
" Total years of production.
• Economic viability of the project (first-year closure).
• Present value of all project costs.
» Present value of all project revenues.
• Present value of additional pollution control costs.
• Present value of severance tax payments.
• Present value of corporate income tax payments.
• Present value of royalties.
• Corporate cost per unit of production.
• Production cost per unit of production.
The analysis of the economic status of the baseline case (presented in Section 5.2) focuses on the
first few parameters listed above as performance measures. The analysis of regulated cases
includes comparisons between the base case statistics and regulated case results.
The net present value is calculated as the difference between the present values of all cash
inflows and all cash outflows associated with a platform (from the perspective of the firm). A
positive value indicates that a project generates more revenues than would be realized by
investing the capital elsewhere in a different opportunity with an expected rate of return equal to
the cost of capital used in this analysis.
5-10
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Total lifetime production sums the stream of future petroleum production.
The, present value equivalent of production is defined as the value of the discounted stream
of future petroleum production.
Total years of production is calculated as the number of years the project will operate with
a positive cash flow. The model can estimate annual cash flows over a 30-year lifetime. The
model assumes that a platform will stop producing when cash flow is negative (i.e., when current
variable costs exceed current revenues).5
The corporate cost per unit of production is defined as the present value of all net
corporate cash outflows for the project life (Le., the cost of operation, royalties, severance tax
and income tax payments, with adjustments made for tax savings based on depreciation and
depletion) divided by the present value of all production (e.g., BOB of oil and gas production).
The present value calculations use a cost-of-capital interest rate of 8 percent to discount costs,
cash flow, and production. If the corporate cost per unit of production is lower than the
projected wellhead selling price, the project is considered viable.
The production cost per unit of production is a measure of the value of net social
resources expended in operation of coastal petroleum projects. In contrast to the corporate cost,
the production cost ignores the effect of transfers that do not use social resources, such as
income taxes, revenue taxes, and royalties. The present values of all investment costs and
operating costs are included in the calculation of this cost. The sum of these costs is divided by
the present value equivalent of production to obtain production costs.
sln Cook Inlet, variable costs are the baseline operating costs plus (in postcompliance
scenarios) the O&M cost component of pollution control costs. Fixed costs do not play a role in
the production decision. In the Gulf, however, for simplicity, capital costs for compliance
equipment are annualized and added to O&M costs of compliance to compute a cost per barrel
of produced water disposed. These costs become variable costs, much as if the facility were
operating on a commercial basis (see Appendix C).
5-11
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5.1.5 Parameter Values and Data Sources
For all Cook Inlet platforms, previously expended costs (e.g., of leasing, exploration,
delineation, and platform installation) are considered sunk costs. All modeling uses a set of
common parameter values (summarized in Table 5-1). All costs are assumed to be in 1992
dollars (or are deflated/inflated to 1992 dollars), and year 1 in the model is 1996, the year the
regulation is assumed to go into effect. Although the regulation is not expected to be
promulgated until late 1996, partial years cannot be modeled for impacts. Thus, to be
conservative, the model reflects cost increases at the beginning of 1996.
5.13.1 Drilling Schedule and Drilling Cost per Well
The planned drilling programs in Cook Inlet are summarized in Section Four (see
Table 4-3). Drilling is projected to occur from 1996 through 2002, with no drilling planned for
1999 or 2001. The economic model for each platform has been modified to reflect the costs for
the new and recompleted wells in the baseline case (that is, the economic profile of platforms
before compliance cost are incurred).
Several assumptions were made in developing the drilling schedule from the information
submitted to EPA by the Cook Inlet operators. The assumptions are as follows:
The regulation takes effect in 1996.
Wells that are planned to be drilled in a time window that includes 1996 are
assumed to be drilled in 1996 (e.g., if a drill date possibility spans 1994-1996, the
well is assumed to be drilled in 1996).
All other wells are drilled in the earliest possible years after 1996, given their
planning window (e.g., if the well is to be drilled sometime between 1997 and
1999, the well is assumed to be drilled in 1997), with one exception. Since no
more than four rigs are available at any one time to Marathon/UNOCAL, and
assuming a 3-month drill schedule, a maximum of 16 wells can be drilled in any
one year. Based on the above assumptions, too many wells would be scheduled
for 1996. Thus, one group of three wells drilled on the Monopod platform was
arbitrarily assigned to 1997 (the time window for drilling on this platform spanned
1995-1998).
5-12
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The model differentiates drilling costs between new production wells and recompletions.
Drilling costs for new wells include costs to drill three segments of a well. Recompletion costs
include costs to recomplete the third segment of a well. Section 308 survey data estimated a per-
well cost for new production wells at $4.1 million and the cost for recompletions at $1.4 million
(SAIC, 1994). It is assumed that the oil company elects to expense intangible drilling costs
(IDCs) incurred in the development of oil and gas wells. IDCs are estimated, on the average, to
represent 60 percent of the cost of production wells and their infrastructure (Commerce, 1982;
Commerce, 1983; API, 1986). The Tax Reform Act limits major integrated oil producers to
expensing 70 percent of IDCs with the remaining 30 percent capitalized (that is, a major may
only expense 0.60 times 0.70, or 42 percent of its costs of production wells and infrastructure).
The remaining 58 percent of the total cost of production wells and infrastructure is capitalized
and treated as depreciable assets for tax purposes (Snook and Magnuson, 1986). It is important
to note that these capital costs can be depredated using the Modified Accelerated Capital
Recovery System (MACRS) over a 7-year period (see Appendix A). The capital cost is taken
into account with present value modifications once all depreciation and tax shield benefits are
accounted for by the model.
5.13 J Production Rates
Production rates for the Cook Inlet platforms were available for three years: 1991 and
1993 data are taken from the information provided to EPA by the Alaska Oil and Gas
Association (AOGA), and 1992 data are taken from the Coastal Oil and Gas Questionnaire
(AOGA, 1991; AOGA, 1993; EPA, 1993a). Since the 1993 data are the most recent that are
available and, thus, reflect increased production from recent drilling efforts, they are used as the
basis for estimating production in 1996. The exceptions are Dillon and Spark, which had
production suspended in 1993; 1991 production levels were used to estimate production in 1996.
Based on survey responses, all platforms except Steelhead and Tyonek A are assumed to
consume all gas produced at the platform.
5-13
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5.1.5.3 Baseline Operation and Maintenance Costs per Platform
For oil-producing platforms, the annual operating cost is estimated as the product of 1993
production rates and a per-barrel operating cost of $7/bbl. This figure was estimated by working
with the model to approximate baseline projections provided by Marathon/UNOCAL (1994b). It
falls within the range for this figure reported by Marathon/UNOCAL (1994a).
For four platforms—Spark, Baker, Dillon, and Bruce—additional operating costs begin
when new or recompleted wells result in substantial production increases. The current oil and
water volume handled by treatment facilities serving these platforms would be increased by an
additional flow 2 to 7.5 times the current flow. We assume that such an increase would result in
additional operating costs to process the produced fluids. The additional annual operating cost
per platform is based on the product of the initial daily production for a new or recompleted well
(500 bpd), the initial number of wells drilled per platform (3 wells for each of Spark, Baker,
Bruce, and billon in 1996 or 1997), the number of days of operation per year (365), and the per-
barrel production costs ($7, as discussed above). The formula is as follows:
initial dairy
per-bttEd
costs
or
500 -3^ x 3 wdb x 365 =^ x
well year bbl
$3,832,500
One of the four platforms was investigated in more detail and the per-barrel production costs
were re-estimated using other information from the model. This information is detailed in an
ERG memorandum (ERG, 1994).
For gas-producing platforms, annual operating costs are based on Section 308 survey data
(EPA, 1993a).
5-14
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5.13.4 Tax Rates
The tax rates used in the model include federal corporate tax rates, severance taxes, and
royalty payments. The federal corporate tax rate is 34 percent and is applicable to all Cook Inlet
operators. Severance taxes were calculated using the ELF. The Alaska Department of Revenue
reports that oil wells in Cook Inlet have not incurred severance taxes for several years (see
Appendix A for more information).
Royalties are based on nonconfidential survey data. The same royalty rates are applied
to all platforms with the same ownership (e.g., all Marathon platforms have an 11.1 percent
royalty on oil production). Royalty rates are presented in Table 5-2 for each of the platforms.
Depreciation for capital expenditures is based on MACRS (details are provided in
Appendix A). For major oil companies, depletion applies to allocation of leasehold costs.
Because the model assumes all prior investments to be sunk, no basis exists for estimating
depletion for the major oil companies operating in Cook Inlet. This omission leads to a slight
underestimate of the profitability of each project in the baseline analysis but has little to no
effect on the incremental impact analysis.
5.1.5.5 Prices
The wellhead price of oil and the wellhead price of gas are presented in Table 5-1. The
value for oil is taken from Marathon/UNOCAL (1994b), in their Zero Discharge Analysis, and is
$14.50 per barrel, an estimated price for 1992 production. Average rates from the Coastal Oil &
Gas Questionnaire survey database are comparable. The wellhead price of gas is scaled from the
price of oil and taken as 10.8 percent of the oil price (U.S. EPA, 1993a). The price of $1.57/Mcf
is comparable to data from the Coastal Oil & Gas Questionnaire (U.S. EPA, 1993a).
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5.1.6 Calculation Procedures
5J..6.1 Production Logic
To determine production at a platform, the model begins production estimates in 1996,
using the production rate estimated above. It is assumed that peak production rates occur in the
first year of production and are maintained for the first year only. The pattern of decline in a
well's productivity can vary greatly due to many factors. Production decline is modeled as an
exponential function (i.e., a constant percentage of the remaining reserves produced in any given
year). This production is assumed to decline by 8 percent annually, a value taken as typical for
Cook Inlet (Marathon/UNOCAL, 1994b). Gas production at the two platforms that do not
consume their gas onsite is also declined at this 8 percent rate. These two values are combined
into a BOE figure.
Increases in production originating with recompleted or new production wells are also
included. When a company drills new wells or recompletes existing wells, corresponding
increases in production at a rate of 500 barrels of oil per day (Marathon/UNOCAL, 1994b) or
15,000 Mcf gas per day (AOGA, 1991) are included.
53 DESCRIPTION OF. THE ECONOMIC MODEL FOR THE GULF OF MEXICO
Although the model for the Gulf of Mexico is similar to the model used for Cook
Inlet—indeed the methodology is the same—there are some basic differences, which are
described below. A line-by-line description of the Gulf of Mexico production loss model is
provided in Appendix C.
5.2.1 Economic Model Overview
The Gulf of Mexico model analyzes the effects of regulations on individual wells (rather
than platforms as in Cook Inlet) that discharge produced water in the coastal subcategory.
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These wells discharge produced water through a permitted treatment facility. Unlike the Cook
Inlet model, the Gulf of Mexico model focuses on the well level and is used to investigate the
effects of the regulation on the productive lifetime of the well. Whereas the Cook Inlet model
estimates increases in production at a platform resulting from the addition of new production
wells and recompleted wells drilled over the first 7 years after the regulation is established, the
Gulf of Mexico model assumes no increase in production at the well level.
Incremental costs for produced water disposal are based on engineering costs that would
be incurred by a production facility complying with the regulation (see Section Four for
information on compliance costs). As noted in Section 5.1.4 (footnote), incremental compliance
costs are handled somewhat differently from the Cook Inlet model. For simplicity (because
information on each well served by each affected facility is not available, as it is in Cook Inlet),
pollution control capital costs are annualized over a 10-year period at a discount rate reported by
the respondent in the Section 308 survey or the survey average of 8 percent (if data are missing)
and are added to the operating and maintenance costs to determine an annual cost. This cost is
divided by the total permitted discharge volume of the treatment facility to establish a per-barrel
cost that can be applied to the volume of produced water that each well generates.
For the Gulf of Mexico model, each well was assumed to produce a constant volume of
oil and water combined over its lifetime. As the volume of oil produced declines at an
exponential rate, water production increases proportionally. This ever-increasing water
production increases annual compliance costs each year.
Most data for the individual wells are taken from Section 308 survey responses. For
missing data or outliers, average values from the survey were substituted for the questionable or
missing value (see Appendix A).
Both major oil companies and independent producers own wells that are analyzed in the
Gulf of Mexico production loss model. Although the two types of owners can deduct depletion
from income, they would use different methods. A major oil company must use the cost basis
for depletion, in which the lease cost is deducted over the production lifetime according to the
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proportion of the reserves sold that year. Since the BAT model assumes all cxtsts prior to model
year 1 are sunk costs, annual depletion is $0.
Independent producers have the option of using percentage depletion. The company is
allowed to write off 15 percent of taxable revenues up to and including 1,000 bpd or 6,000 Mcf
per day of production. The Gulf of Mexico model assumes that independent producers will
select this method of depletion and reap the benefits associated with it. The two methods of
depletion are discussed further in Appendix A.
Wells in the Gulf of Mexico production loss model that discharge produced water are
taken from a stratified sample of all wells operating in the Gulf. Once individual well results are
obtained, the results are weighted according to the stratum in which the well was classified.
Results are further adjusted to take into account the estimate of wells drilled prior to 1980 that
are believed to be associated with facilities that will be discharging in 1996 (see Section Three
and detailed discussion in 5.3.1.1). Thus, the results of the production loss model represent the
estimated population of coastal dischargers in the Gulf of Mexico region.
S3 PRODUCTION LOSS MODELING RESULTS
This section presents the results of the production loss modeling for Gulf of Mexico wells
and Cook Inlet platforms. Results are organized into baseline modeling results and
postcompliance modeling results and broken down by region. Postcompliance results include
numbers of first-year shut-ins of wells or platforms by option, production losses, years of
production lost, net present dollar value of production losses, and state and federal revenues lost.
Section 53.1 presents the results of Gulf of Mexico modeling, Section 5.3.2 presents the results
of Cook Inlet modeling for produced water and drilling waste, and Section 5.3.4 presents the
combined results of Gulf of Mexico and Cook Inlet modeling for produced water regulatory
options. Section 53.4 summarizes the total impacts of all the selected regulatory options, and
Section 535 briefly discusses expected impacts from TWC options.
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5.3.1 Gulf of Mexico
5.3J.I Baseline Modeling Results
Option #1—Produced Water
The estimate of the number of wells that are predicted to be associated with facilities
discharging in 1996 when based directly on the section 308 survey (after all facilities on
compliance schedules are removed from the analysis) is 131. When this number is adjusted by
the overall factor of 1.61 used to determine the total number of wells in the Gulf coastal area
(i.e., Louisiana and Texas), a total of 211 discharging wells results, which is only about 1 well per
discharging facility (216 facmties—see Section Three). This estimate is considered unrealistic
and might be caused by the possibility that a large portion of all estimated discharging pre-1980
wells are associated with discharging facilities that will continue to discharge in 1996.
Consequently, an alternative estimate of wells was derived, based in part on the approach
used to calculate the total number of wells in the Gulf coastal region (including pre-1980 wells).
It is estimated that 216 facilities will be discharging in 1996. The number of wells served on
average by discharging facilities in 1996 is estimated using survey data to be 7.35 wells per
facility. Therefore, the total number of wells discharging in 1992 associated with facilities that
will continue to discharge in 1996 is estimated to be 1,588 wells.
Model results are extrapolated based on the 1,588 productive wells estimated to be
discharging hi 1996. According to the baseline analysis, using data provided for wells in the
survey on total production, wellhead price, and an estimate for production costs, 195 of these
wells are estimated to be not economical to produce (and very likely, in fact, have been shut in
since the survey was performed). Thus, 1,393 wells are estimated to be operating and continuing
to discharge in 1996; the number of wells discharging in 1996 is estimated to be 30 percent of the
total 4,675 productive Gulf of Mexico wells.
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The total lifetime production of the 1,393 discharging wells (calculated over a maximum
30-year span) is 253.8 million BOE in present value terms or 354.2 million total BOE.6 The
total productive lifetime of these wells is 24,447 years, or an average of 15.4 years per well
(including baseline shut ins). The net present value of this production, based on an assumption
of constant real wellhead price is $1.2 billion (see Table 5-3 for a summary of baseline data). As
discussed in Section Three, total lifetime production in the Gulf of Mexico (Texas and
Louisiana) is expected to range between 692.5 million BOE and 1,391.2 million discounted BOE,
and the net present value (i.e., the present value of producer net income) ranges from $10.6
billion to $21.3 billion. Thus, baseline production associated with discharging wells is estimated
to be 5.6 percent to 11.3 percent of the total net present dollar value to the producer of total
Gulf of Mexico production and 18 to 37 percent of the Gulfs total lifetime discounted
production.
The total present value of federal and state income tax collected over the economic
lifetime of ithe discharging wells is projected to be $600.6 million or approximately, on average,
$70.2 million annually.7 The present value of severance tax collected over the lifetime of the
discharging wells is expected to be $223.3 million or about $26.1 million, on average, per year.
Additional royalties (present value) paid to the states (and others) are estimated to be $413.9
million, or $48.4 million on average annually. Total state revenues over the lifetime of these
discharging wells are, thus, estimated at $637.2 million, or $74.4 million annually, on average.8
6Barrels of oil equivalent represents the total oil and gas produced, with gas converted to an
equivalent measurement based on the amount of energy in a cubic foot of gas and the number of
cubic feet of gas needed to match the energy in a barrel of oil. The present value of BOE
reflects BOE discounted to the present under the assumption that a barrel of oil today is worth
more than a barrel of oil in the future. It is a useful measure to compare with other present
value figures.
'Present value annualized over the average baseline lifetime of wells in the Gulf
(approximately 15 years).
^or simplicity in this section, royalties are assumed to be paid primarily to the states,
although in the Gulf, some royalties are paid to individuals. In Cook Inlet, all royalties are paid
to the state.
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TABLE 5-3
RESULTS OF THE PRODUCTION LOSS MODELING IN THE GULF REGION
(Produced Water, 1992 $)"
Productive wells in analysis
Total first-year shut-ins
Postcompliance first-year shut-ins
Total wells remaining in analysis
Baseline
1,588
195
—
1,393
Improved
Gas
Flotation
1,588
237
42
1,351
i . , '., " •" - ' ' -
Lifetime discounted production (BOB)
Change in lifetime discounted production
(BOB)
Percentage change
253,785,398
-
-
244,368,043
9,417,355
3.7%
:, • r , ' " '
Total projected lifetime production (BOB)
Change in total lifetime production (BOB)
Percentage change
354,179,441
-
-
331,185,521
22,993,920
6.5%
----- " > f ' - ' "'--, -' * • :
Total production lifetime (years)
Change in production lifetime
Percentage change
24,447
-
-
16,758
7,689
315%
• -,' - '•""„,
:•.'•- ' » ' ;
Average lifetime (years)
Change in average lifetime
Percentage change
15.4
-
• -
10.6
4.8
31.2%
; %-.-.'•'• .-< ff s
**•,•. •• *•
Present value of producers' net income
(NPV) ($000)
Change in NPV ($000)
Percentage change
1,183,255
-
-
1,077^33
105,922
9.0%
Zero
Discharge
1,588
306
111
1,282
-
241,723,591
12,061,807
4.8%
'
326,421,312
27,758,129
7.8%
15,197
9,249
9.6
5.8
37.7%
•>' '
1,038,775
144,480
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TABLE 5-3 (cont)
Baseline
Improved
Gas
Flotation
Zero
Discharge
; * ;' S^V s ';£:s':',\ '^?;£ ":'-; ' „'„ '„' '*,^''
Present value of federal and state income tax
collected ($000)
Change in income tax collected ($000)
Percentage change
! .• ^ •• •. ,• ' \ ' *•>
1r> > fff r ', f; t,', v.
Present value of severance tax collected
($000)
Change in severance tax collected ($000)
Percentage change
600,626
-
'
^%£Z? 4
223,267
-
-
544,559
56,068
9.3%.
520,975
79,651
13.3%
','-",** ' v ^ " '^
217,835
5,433
2.4%
212,750
10,517
4.7%
s s - "" ' , "' -?- - '"*' '" ' 4?' ^ -^m^i "- 'T *' k , ;
Present value of royalties collected ($000)
Change in royalties collected ($000)
Percentage change
413,925
-
-
398,114
15,810
3.8%
384,867
29,058
7.0%
•Baseline reflects values for discharging wells only. Total Gulf coastal baseline figures would be
much greater in most categories.
Note: Results are weighted using well survey weights and adjustment factors noted in the text:
Source: ERG estimates.
5-22
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5.3.13 PostcompKance Production Loss
Option #2—Produced Water
When the compliance costs associated with installing and operating improved gas
flotation systems are added to the baseline operating costs for the model wells, 42 wells are
estimated to shut in immediately in response to the regulation incremental to those that close in
the baseline.
These 42 first-year shut-ins and reduction in the economic lifetime of discharging wells
lead to declines in production totaling 9.4 million discounted BOB (23.0 million total BOB) over
the remaining life of the wells, or a decline of 3.7 percent among the discharging wells. Lifetime
production loss is expected to range between 0.7 percent and 1.4 percent of total estimated Gulf
of Mexico lifetime production (present value). The net present dollar value of this production
loss to producers totals $105.9 million ($15.8 million annually), or 9.0 percent of the net present
value of producers' income projected for discharging wells. This loss is only 0.5 to 1.0 percent
of the net present value of producers' income among all Gulf of Mexico (Louisiana and Texas)
wells.
The total number of well years of productive life lost is 7,689, which is 31.5 percent of all
years estimated to remain among discharging wells in the baseline. Since average lost productive
life is 4.8 years, average postcompliance life is 10.6 years among discharging wells. Note that
production losses are a far lower percentage of discharging well production than years lost; thus,
a considerable portion of the production losses is likely to be associated with marginal weHs that
might have a number of years of production remaining but that produce relatively little oil or
gas.
The total present value of the lifetime loss of federal and state income tax is estimated to
be $56.1 million ($8.4 million lost per year on average over the approximately 10 years of average
well lifetime remaining). This loss is 9.3 percent of the total present value of income tax
expected to be collected from discharging Gulf of Mexico wells over their productive lifetime,
nearly all of which is federal income tax.
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The total present value of the loss of state severance taxes over the life of the discharging
wells is estimated to be $5.4 million or $0.8 million annually on average, or 2.4 percent of the
present value of severance tax receipts in the baseline from discharging wells over their
productive lifetimes. Royalties lost are estimated to total $15.8 million ($2.4 million annually, on
average), for a total present value loss to the states (in severance and royalties) of up to $21.2
million over the productive lifetime of the discharging wells ($3.2 million annually).
Table 5-3 summarizes the impacts of the improved gas flotation option on Gulf of Mexico
discharging wells.
Options #3, #4, and #5—Produced Water
When the compliance costs associated with meeting zero discharge requirements in the
Gulf for produced water are added to the baseline operating costs for the model wells, 111 wells
are estimated to shut in immediately in response to the regulation incremental to those that close
in the baseline.
These first-year shut-ins and reduction in the economic lifetime of discharging wells lead
to declines in production totaling 12.1 million discounted BOE (27.8 million total BOB), or a
decline of 4.8 percent among the discharging wells (present value). Lifetime production loss is
expected to range between 0.9 and 1.7 percent of total estimated lifetime production in the Gulf.
Producers lose $144.5 million in net present value of income ($21.5 million annually), or 12.2
percent of their projected net present value. This loss is only 0.7 to 1.4 percent of the projected
net present value of income among all Gulf of Mexico operators.
The total number of well years of productive life lost is 9,249, which is 37.8 percent of all
years estimated to remain among discharging wells in the baseline. Since average lost productive
life is 5.8 years, average postcompliance life is 9.6 years among discharging wells. Note that
production losses are a far lower percentage of discharging well production than years lost; thus,
a considerable portion of the production losses is likely to be associated with marginal wells that
5-24
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might have a number of years of production remaining but that produce relatively little oil or
gas.
Total loss (in present value) of federal and state income tax is estimated to be $79.7
million over the productive life of the discharging wells ($11.9 million, on average, annually over
the approximately 10 years of average well lifetime remaining), which is 13.3 percent of the total
federal and state income tax (nearly all federal) expected to be collected from discharging Gulf
of Mexico wells over their productive lifetime.
The total present value loss of state severance taxes is estimated to be $10.5 million over
the productive life of the discharging wells ($1.6 million, on average, annually), or 4.7 percent of
severance tax receipts in the baseline from discharging wells. The total present value of royalties
lost is estimated to total $29.1 million (or $4.3 million, on average, annually), for a total present
value loss to the states (in severance and royalties) of up to $39.6 million over the productive life
of the discharging wells ($5.9 million annually).
533 Cook Inlet
5.3.2.1 Produced Water
Baseline Analysis Results (Option #\ and #3)
Currently in Cook Inlet 14 platforms are either operating or are projected to be
operating (i.e., the operator has plans for drilling). These 14 platforms, none of which close in
the baseline, are estimated to produce 198.1 million discounted BOB (306.9 million total BOB)
over the lifetime of these platforms without any further regulatory action. The net present value
of producer income (i.e., the present value of their projected net income stream) of this lifetime
production is $416.2 million ($62.0 million annually). These platforms are estimated to operate
for a total of 156 platform-years, or 11.1 years on average. The present value of severance taxes
collected totals an estimated $60.3 million ($8.4 million, on average, annually over the 11 years of
platform lifetime remaining), the present value of royalties to the state total $264.1 million
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($37.0 million, on average, annually), and the present value of federal income taxes collected are
projected to total $241.0. million ($33.8 million, on average, annually) (see Table 5-4).
Option #2 and #4 Results
Both Option #2 and #4 require offshore limits to be met (i.e., improved gas flotation)
among the Cook Inlet platforms. Use of improved gas flotation has the following effects on
production in the Cook Inlet: No platforms are projected to shut in during the first year. Total
lifetime production in Cook Inlet drops by 3.1 million discounted BOE to 195.0 million
discounted BOE (a loss of 4.6 million total BOE). This reduction is 1.6 percent of lifetime
discounted production in the Cook Inlet. Producers' net present value drops $8.7 million to
$407.5 million ($60.7 million annually). This net .present value loss is 2.1 percent of baseline
projected net present value among Cook Inlet producers. Average production years per platform
drop from ll.l to 10.7 years, thus, the installation and operation of improved gas flotation will
result in platforms shutting in an average of 5 months earlier than they would have without the
regulation.
The total present value of lifetime federal income taxes lost under this option are
estimated to be $5.3 million ($0.7 million, on average, annually over the 11-year life of platforms
estimated under this option), or 2.2 percent of the baseline federal taxes estimated to be
collected over the life of the platforms. The present value of severance taxes lost total $159,000
over the life of the platforms ($22,000, on average, annually). Royalties lost to the state total
$5.2 million over the life of the platforms ($0.7 million, on average, annually), or 2.0 percent of
the baseline royalties collected (see Table 5-4).
Option #5 Results
Option #5 is the only produced water option requiring Cook Inlet platforms to meet
zero-discharge requirements. Under a zero-discharge requirement, three platforms shut in
during the first year and Cook Inlet lifetime production drops by 16.0 million discounted BOE
5-26
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5-27
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(225 million total BOE), or 8.8 percent of baseline production. Producers' projected net present
value drops by $915 million, which is 28.2 percent of their baseline net present value ($13.6
million annually). The average productive life of the platforms drops to 8.9 years, although
among platforms remaining active, this average is 11.3 years (this number is higher than the
baseline years of operation because the three platforms that shut in under Option #5 pulled
down the average in the baseline).
The total present value loss of federal income taxes is estimated to total $40.2 million
over the lifetime of the Cook Inlet platforms under this option ($5.6 million annually over the
11-year life, on average), which is 20.0 percent of projected income tax receipts in the baseline.
The present value of severance taxes lost are estimated to be $0.8 million over the lifetime of the
Cook Inlet platforms ($0.1 million, on average, annually), or 1.4 percent of total baseline
severance taxes estimated to be collected. Loss in royalty payments to the state (in present value
terms) will total $28.8 million over the life of the platforms ($4.0 million, annually, on average),
or 12.2 percent of baseline royalties collected. The present value of total lifetime lost revenues
to the state are, thus, $29.6 million ($4.1 million, on average, annually) (see Table 5-4).
5.32 a Drilling Fluids
Baseline Analysis Results (Option #1)
Option #1 results are identical to the baseline results under Option #1 for Produced
Water in Cook Inlet (see Section 5.3.2.1 above and Table 5-5).
Option #2
Option #2 requires drilling wastes to meet a 100,000- to 1-million-ppm toxicity limit, in
addition to offshore requirements. As discussed in EPA's Development Document (EPA, 1995),
only 17 percent of the drilling waste is expected to fail to meet this limit; thus, only 17 percent of
all drilling waste in Cook Inlet will require disposal other than discharge. Under this option,
5-28
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5-29
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there is a loss of lifetime production in Cook Inlet of 2.7 million discounted BOE (3.6 million
total BOE), or 1.4 percent of total lifetime Cook Inlet production (stemming from three wells
that -will not be drilled under this scenario); no platforms shut in during the first year; and the
present value of net producer income fells by $03 ($0.04 million annually) million, or less than
0.1 percent of baseline net present value.9 Average platform lifetime decreases by only 0.2 years
(2 months). The present value of state severance tax collections falls by $133,000 ($19,000
annually, on average over the 11-year life of platforms under this option, or 0.2 percent of
baseline) and the present value of royalties decreases by $4.3 million ($0.6 million, on average,
annually, or 1.6 percent of baseline). The present value federal tax collections fells by $2.6
million over the life of the platforms ($0.4 million, on average, annually), or 1.1 percent of
projected baseline collections (see Table 5-5).
Option #3
Option #3 requires zero discharge of all drilling waste. Under this option, no platforms
shut in during the first year, but six wells that are planned to be drilled will not be drilled. The
total lifetime production lost is estimated to be 5.4 million discounted BOE (7.8 million total
BOE), or 2.8 percent of lifetime baseline production. Producers' net present value of income
lost totals $6.1 million ($0.9 million annually), which is 1.5 percent of total baseline net present
value of income. The average number of production years per platform under this option is 10.2
years, vs. 11.1 years in the baseline scenario, a loss of about 1 year.
The present value loss of federal income tax over the lifetime of the platforms is
projected to be $7.9 million ($1.2 million, on average, annually over the 10-year life of platforms
under this option, or 3.4 percent of baseline federal income taxes), with the present value of
This loss is very small because of a baseline model assumption for one platform. Industry
sources have indicated that three wells will be drilled on the platform. Model runs, however,
indicated that the platform would be more profitable without the three wells. Since under post-
compliance scenarios the three wells cannot be drilled without the platform operating at a loss,
these wells are assumed not to be drilled. This assumption leads to an increase in net present
relative to the baseline, although not so much of an increase as to offset all losses in net present
value stemming from compliance costs.
5-30
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severance .tax losses totaling $0.3 million ($0.04 million, on average, annually, or 0.5 percent of
baseline severance taxes). The present value of royalty losses to the state totals $9.4 million
($1.4 million, on average, annually), or 3.7 percent of the baseline royalties collected. Total
present value losses to the state from royalties and severance taxes lost are, thus, $9.7 million
($1.44 million, oh average, annually) (see Table 5-5).
5.3.3 Total Impacts—Gulf of Mexico Wells and Cook Inlet Platforms, Produced Water
Options
As Table 5-6 shows, total produced water impacts across both regions tend to increase
with option number. Options #2, #3, and #4 show moderate, incremental increases in impacts,
whereas.Option #5, in many instances shows a large incremental change in impacts from Option
#4. In many cases, Option #5 impacts are two times greater than Option #2 impacts.
The selected option, Option #4, is associated with 111 wells and no platforms shutting in
and losses in production totaling 15.2 million discounted BOB (which is at most 1.7 percent of
total projected lifetime production in the Gulf of Mexico and Cook Inlet combined) or 32.4
million total BOB. The net present value lost by producers totals $153.2 million ($22.8 million
annually), or at most 1.4 percent of their baseline projected net present value in the Gulf of
Mexico and Cook Inlet combined. Note that these losses include the producers' share of
compliance costs (posttax costs). The present value of income taxes lost are estimated at $84.9
million ($12.7 million on average annually) over a 10-year expected life, or 10.1 percent of taxes
collected from discharging coastal wells and platforms in the Gulf of Mexico and Cook Inlet.
The present value of severance tax losses under Option #4 totals $10.7 million ($1.6 million on
average annually), or 3.8 percent of projected baseline collections in the Gulf of Mexico and
Cook Inlet among discharging coastal wells and platforms. Finally, royalties lost to the states
total $34.3 million ($5.1 million on average annually), or 5.1 percent of projected baseline
royalties to the states in the Gulf of Mexico and Cook Inlet among discharging coastal wells and
platforms.
5-31
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